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 September 30, 2015

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.)

200 Columbine Street, Suite 500
Denver, CO	80206
(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). Yes x  No ¨

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

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

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

As of November 6, 2015, there were 8,708,499 shares of Common Stock, $0.001 par value per share, outstanding.

EMERALD OIL, INC.

INDEX

			Page of
			Form 10-Q
PART I.	FINANCIAL INFORMATION		1
	ITEM 1.	FINANCIAL STATEMENTS (UNAUDITED)	1
		Condensed Consolidated Balance Sheets as of September 30, 2015 and December 31, 2014	1
		Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2015 and 2014	2
		Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2015 and 2014	3
		Notes to Condensed Consolidated Financial Statements	4
	ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	22
	ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	37
	ITEM 4.	CONTROLS AND PROCEDURES	38
PART II.	OTHER INFORMATION		38
	ITEM 1.	LEGAL PROCEEDINGS	38
	ITEM 1A.	RISK FACTORS	38
	ITEM 6.	EXHIBITS	42
SIGNATURES			44

PART 1 — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

EMERALD OIL, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	September 30, 2015			December 31, 2014
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	5,068,320		$	12,389,230
Accounts Receivable – Oil and Natural Gas Sales		4,002,942			7,203,455
Accounts Receivable – Joint Interest Partners		8,370,512			31,842,464
Other Receivables		860,980			980,317
Prepaid Expenses and Other Current Assets		681,581			289,061
Fair Value of Commodity Derivatives		6,336,057			5,044,125
Total Current Assets		25,320,392			57,748,652
PROPERTY AND EQUIPMENT
Oil and Natural Gas Properties, Full Cost Method, at cost:
Proved Oil and Natural Gas Properties		697,814,220			593,472,170
Unproved Oil and Natural Gas Properties		141,768,220			166,708,263
Equipment and Facilities		15,220,754			6,086,896
Other Property and Equipment		4,266,762			2,583,372
Total Property and Equipment		859,069,956			768,850,701
Less – Accumulated Depreciation, Depletion and Amortization		(486,650,786	)		(149,703,417	)
Total Property and Equipment, Net		372,419,170			619,147,284
Restricted Cash		—			4,000,000
Fair Value of Commodity Derivatives		1,375,070			—
Debt Issuance Costs, Net of Amortization		4,183,174			5,779,125
Deposits on Acquisitions		—			140,173
Deferred Tax Assets, Net		1,813,561			1,813,796
Other Non-Current Assets		329,572			430,846
Total Assets	$	405,440,939		$	689,059,876
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts Payable	$	38,762,753		$	120,136,903
Revolving Credit Facility		159,683,000			—
Convertible Senior Notes		151,500,000			—
Accrued Expenses		5,073,975			11,267,831
Advances from Joint Interest Partners		802,119			2,577,247
Deferred Tax Liability, Net		1,813,561			1,813,796
Total Current Liabilities		357,635,408			135,795,777
LONG-TERM LIABILITIES
Revolving Credit Facility		—			75,000,000
Convertible Senior Notes		—			151,500,000
Asset Retirement Obligations		3,265,518			2,671,975
Warrant Liability		187,000			2,199,000
Fair Value of Commodity Derivatives		—			—
Total Liabilities		361,087,926			367,166,752
COMMITMENTS AND CONTINGENCIES
Preferred Stock – Par Value $.001; 20,000,000 Shares Authorized;
Series B Voting Preferred Stock – 255,732 issued and outstanding at September 30, 2015 and December 31, 2014. Liquidation preference value of $256 as of September 30, 2015 and December 31, 2014.		256			256
STOCKHOLDERS’ EQUITY
Common Stock, Par Value $.001; 500,000,000 Shares Authorized, 8,708,499 and 3,891,431 Shares Issued and Outstanding, respectively		8,709			3,891
Additional Paid-In Capital		507,612,218			455,087,277
Accumulated Deficit		(463,268,170	)		(133,198,300	)
Total Stockholders’ Equity		44,352,757			321,892,868
Total Liabilities and Stockholders’ Equity	$	405,440,939		$	689,059,876

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

1

EMERALD OIL, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
REVENUES
Oil Sales	$	17,350,524		$	28,266,332		$	52,981,871		$	76,989,268
Natural Gas Sales		494,804			460,857			1,224,667			2,061,201
Net Gains on Commodity Derivatives		12,699,147			11,184,716			8,148,386			3,722,780
Total Revenues		30,544,475			39,911,905			62,354,924			82,773,249
OPERATING EXPENSES
Production Expenses		8,201,949			6,962,450			25,972,453			13,477,176
Production Taxes		1,653,989			3,142,998			5,488,364			8,632,608
General and Administrative Expenses		3,821,473			5,483,655			12,495,471			21,609,218
Depletion of Oil and Natural Gas Properties		11,242,324			9,193,566			31,622,386			24,071,676
Impairment of Oil and Natural Gas Properties		158,278,000			—			304,903,000			—
Depreciation and Amortization		232,350			104,465			559,139			251,722
Accretion of Discount on Asset Retirement Obligations		52,500			28,037			153,007			63,837
Standby Rig Expense		3,800,446			—			6,173,111			—
Total Operating Expenses		187,283,031			24,915,171			387,366,931			68,106,237
INCOME (LOSS) FROM OPERATIONS		(156,738,556	)		14,996,734			(325,012,007	)		14,667,012
OTHER INCOME (EXPENSE)
Interest Expense		(2,735,348	)		(1,206,571	)		(7,044,901	)		(2,515,034	)
Warrant Revaluation Gain (Expense)		221,000			216,000			2,012,000			(1,751,000	)
Other Income (Expense)		281			(347,088	)		539			(343,041	)
Total Other Expense, Net		(2,514,067	)		(1,337,659	)		(5,032,362	)		(4,609,075	)
INCOME (LOSS) BEFORE INCOME TAXES		(159,252,623	)		13,659,075			(330,044,369	)		10,057,937
INCOME TAX PROVISION		—			—			—			—
NET INCOME (LOSS)	$	(159,252,623	)	$	13,659,075		$	(330,044,369	)	$	10,057,937
Net Income (Loss) Per Common Share – Basic	$	(19.85	)	$	4.11		$	(52.10	)	$	3.03
Net Income (Loss) Per Common Share - Diluted	$	(19.85	)	$	3.29		$	(52.10	)	$	2.89
Weight Average Shares Outstanding – Basic		8,021,992			3,324,970			6,334,549			3,316,751
Weighted Average Shares Outstanding –Diluted		8,021,992			4,419,020			6,334,549			4,093,377

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)

	Nine Months Ended September 30,
	2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss	$	(330,044,369	)	$	10,057,937
Adjustments to Reconcile Net Loss to Net Cash Provided By Operating Activities:
Depletion of Oil and Natural Gas Properties		31,622,386			24,071,676
Impairment of Oil and Natural Gas Properties		304,903,000			—
Depreciation and Amortization		559,138			251,722
Amortization of Debt Issuance Costs		2,145,832			727,997
Accretion of Discount on Asset Retirement Obligations		153,007			63,837
Net Gains on Commodity Derivatives		(8,148,386	)		(3,722,780	)
Net Cash Settlements Received (Paid) on Commodity Derivatives		5,481,384			(2,775,591	)
Warrant Revaluation (Gain) Expense		(2,012,000	)		1,751,000
Share-Based Compensation Expense		2,710,683			9,497,044
Changes in Assets and Liabilities:
Decrease (Increase) in Trade Receivables – Oil and Natural Gas Revenues		3,200,513			(1,390,582	)
Decrease (Increase) in Accounts Receivable – Joint Interest Partners		23,471,952			(1,224,056	)
Decrease (Increase) in Other Receivables		119,337			(1,132,418	)
Increase in Prepaid Expenses and Other Current Assets		(392,520	)		(223,875	)
(Increase) Decrease in Other Non-Current Assets		(35,882	)		67,463
(Decrease) Increase in Accounts Payable		6,585,509			2,364,168
Decrease in Accrued Expenses		(4,867,351	)		(7,813,470	)
Increase in Other Non-Current Liabilities		—			198,551
(Decrease) Increase in Advances from Joint Interest Partners		(1,775,128	)		200,434
Net Cash Provided By Operating Activities		33,677,105			30,969,057
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of Other Property and Equipment		(1,683,390	)		(1,015,677	)
Restricted Cash Released		4,000,000			11,000,512
Payments of Restricted Cash		—			(2,648,721	)
Decrease (Increase) in Deposits for Acquisitions		140,173			(648,441	)
Proceeds from Sale of Oil and Natural Gas Properties, Net of Transaction Costs		—			36,155,859
Investment in Oil and Natural Gas Properties		(175,371,888	)		(391,368,324	)
Net Cash Used For Investing Activities		(172,915,105	)		(348,524,792	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Issuance of Convertible Senior Notes, Net of Transaction Costs		—			166,893,211
Proceeds from Issuance of Common Stock, Net of Transaction Costs		48,049,115			—
Advances on Revolving Credit Facility		100,000,000			55,000,000
Payments on Revolving Credit Facility		(15,317,000	)		(35,000,000	)
Cash Paid for Finance Costs		(265,144	)		(24,605	)
Cash Paid for Debt Issuance Costs		(549,881	)		(1,117,871	)
Proceeds from Exercise of Stock Options and Warrants		—			110,750
Net Cash Provided by Financing Activities		131,917,090			185,861,485
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(7,320,910	)		(131,694,250	)
CASH AND CASH EQUIVALENTS – BEGINNING OF PERIOD		12,389,230			144,255,438
CASH AND CASH EQUIVALENTS – END OF PERIOD	$	5,068,320		$	12,561,188
Supplemental Disclosure of Cash Flow Information
Cash Paid During the Period for Interest	$	4,124,010		$	1,867,433
Cash Paid During the Period for Income Taxes	$	—		$	—
Non-Cash Financing and Investing Activities:
Oil and Natural Gas Properties Included in Accounts Payable	$	19,997,664		$	92,963,874
Stock-Based Compensation Capitalized to Oil and Natural Gas Properties	$	708,600		$	2,020,992
Asset Retirement Obligation Costs and Liabilities	$	440,536		$	1,669,757

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 focused on acquiring acreage and developing oil and natural gas wells in the Williston Basin of North Dakota and Montana. The Company designs, drills and operates oil and natural gas wells on acreage where it holds a controlling working interest. The Company also participates in the drilling of oil and natural gas wells operated by other companies.

NOTE 2  BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES

The accompanying condensed consolidated financial statements have been prepared on the accrual basis of accounting whereby revenues are recognized when earned and expenses are recognized when incurred. The condensed consolidated financial statements as of September 30, 2015 and for the three and nine months ended September 30, 2015 and 2014 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 condensed consolidated financial statements as of September 30, 2015 and for the three and nine months ended September 30, 2015 and 2014.

Interim financial results should be read in conjunction with the audited financial statements and footnotes for the year ended December 31, 2014, which were included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2014.

Reverse Stock Split

On May 20, 2015, a majority of the Company’s stockholders approved a 1-for-20 reverse stock split pursuant to which all stockholders of record received one share of common stock for each twenty shares of common stock owned (subject to minor adjustments as a result of fractional shares), which the Company’s board of directors had previously authorized.. This reverse stock split decreased the issued and outstanding shares of common stock by approximately 105,274,000 shares, the number of shares of common stock underlying outstanding warrants by approximately 5,919,000 shares, outstanding stock options by approximately 955,000 shares and the number of shares of common stock underlying the outstanding 2.0% Convertible Senior Notes due 2019 (the “Convertible Notes”) by 16,402,000 shares. GAAP requires that the reverse stock split be applied retrospectively to all periods presented. As a result, all shares of common and preferred stock, warrants and stock options, as well as any other common stock derivatives, described herein have been adjusted to reflect the 1-for-20 reverse stock split.

Cash and Cash Equivalents

The Company considers highly liquid investments with insignificant interest rate risk and original maturities of three months or less to be cash equivalents. Cash equivalents consist primarily of interest-bearing bank accounts and money market funds. The Company’s cash positions represent assets held in checking and money market accounts. These assets are generally available to the Company on a daily or weekly basis and are highly liquid in nature. Due to the balances being greater than their $250,000 insurance coverage, the Company does not have FDIC coverage on the entire amount of its bank deposits. The Company believes this risk to be minimal. In addition, the Company is subject to Security Investor Protection Corporation protection on a vast majority of its financial assets in the event one of the brokerage firms that the Company utilizes for its investments fails.

Restricted Cash

Restricted cash included in current and long-term assets on the condensed consolidated balance sheets totaled $0 and $4 million at September 30, 2015 and December 31, 2014, respectively.  At December 31, 2014, the balance related to a drilling commitment agreement entered into pursuant to oil and natural gas leases. The commitment was fulfilled and funds released during the three months ended September 30, 2015.

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 nine months ended September 30, 2015 and 2014.

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 September 30, 2015 and 2014, the Company capitalized $814,011 and $1,354,556, respectively, of internal salaries, which included $78,390 and $624,629, respectively, of stock-based compensation. For the nine months ended September 30, 2015 and 2014, the Company capitalized $3,245,667 and $4,278,105, respectively, of internal salaries, which included $708,600, and $2,020,992, 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 nine months ended September 30, 2015 and 2014.

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 nine months ended September 30, 2015 and 2014. 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 nine months ended September 30, 2015 and the year ended December 31, 2014, the Company included $15,231,547 and $2,979,258, 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. Any required write-downs are included in the consolidated statement of operations as an impairment charge. Based on calculated reserves at September 30, 2015, the unamortized costs of the Company’s oil and natural gas properties exceeded the ceiling test limit by $158,278,000. As a result, the Company was required to record impairments of the net capitalized costs of its oil and natural gas properties in the amount of $158,278,000 and $304,903,000 for the three and nine months ended September 30, 2015, respectively. As of September 30, 2014, the unamortized costs of the Company’s oil and natural gas properties did not exceed the ceiling test limit and no impairment expense was recognized for the three and nine months ended September 30, 2014.

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.

5

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 it can be reasonably estimated 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 September 30, 2015 and December 31, 2014, 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 of peer company data fairly represents the expected volatility it would experience if it were in the oil and natural gas industry over the expected term of the options. The Company used the simplified method to determine the expected term of the options due to the lack of historical data. Changes in these assumptions can materially affect the fair value estimate.

On May 27, 2011, the stockholders of the Company approved the 2011 Equity Incentive Plan (the “2011 Plan”), under which 35,714 shares of common stock were reserved. On October 22, 2012, 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 175,000 shares. On July 10, 2013, the stockholders of the Company approved an amendment to the 2011 Plan to increase the number of shares authorized for issuance under the 2011 Plan to 490,000 shares. On May 20, 2015, the stockholders of the Company approved an amendment to the 2011 Plan to increase the number of shares authorized for issuance under the 2011 Plan to 990,000 shares. The purpose of the 2011 Plan is to promote the success of the Company and its affiliates by facilitating the employment and retention of competent personnel and by furnishing incentives to those officers, directors and employees upon whose efforts the success of the Company and its affiliates will depend to a large degree. It is the intention of the Company to carry out the 2011 Plan through the granting of incentive stock options, nonqualified stock options, restricted stock awards, restricted stock unit awards, performance awards and stock appreciation rights. As of September 30, 2015, 42,491 stock options and 380,396 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 72,092 nonvested restricted stock units. As of September 30, 2015, there were 567,113 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.

6

The tax effects from an uncertain tax position can be recognized in the financial statements only if the position is more likely than not of being sustained if the position were to be challenged by a taxing authority. The Company has examined the tax positions taken in its tax returns and determined that there are no uncertain tax positions. As a result, the Company has recorded no uncertain tax liabilities in its condensed 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 shares of common stock outstanding during the period. Diluted earnings per share are computed using the weighted average number of shares of common stock 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 nine months ended September 30, 2015 and 2014, the potentially dilutive shares were anti-dilutive and were thus not included in the net loss per share calculation.

As of September 30, 2015, (i) 72,092 nonvested restricted stock units were issued and outstanding and represent potentially dilutive shares; (ii) 30,759 stock options were issued and presently exercisable and represent potentially dilutive shares; (iii) 9,777 stock options were granted but were not presently exercisable and represent potentially dilutive shares; (iv) 255,732 warrants were issued and presently exercisable, which have an exercise price of $9.52 and represent potentially dilutive shares; (v) 11,165 warrants were issued and presently exercisable, which have an exercise price of $137.20 and represent potentially dilutive shares; (vi) 44,643 warrants were issued and presently exercisable, which have an exercise price of $994.00 and represent potentially dilutive shares; and (vii) $151.5 million of Convertible Notes were convertible into approximately 863,248 shares of common stock as of September 30, 2015 and represent 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’ creditworthiness, the Company’s creditworthiness, 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 marketplace participant’s view. Management believes that this approach provides a reasonable, non-biased, verifiable, and consistent methodology for valuing commodity derivative instruments (see Note 13 – Derivative Instruments and Price Risk Management).

Warrant Liability

From time to time, the Company may have financial instruments such as warrants that may be classified as liabilities when either (a) the holders possess rights to net cash settlement, (b) physical or net equity settlement is not in the Company’s control, or (c) the instruments contain other provisions that cause 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 6 – Preferred and Common Stock), the Company issued warrants that contain a put and other liability type provisions. Accordingly, these warrants are accounted for as a liability. This warrant liability is accounted for at fair value with changes in fair value reported in the consolidated statement 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.

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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, valuation of asset retirement obligations 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 LIQUIDITY AND CAPITAL RESOURCES

As of September 30, 2015, the Company had available cash of approximately $5.1 million, availability under its reserve-based revolving credit facility (the “Credit Facility”) with Wells Fargo Bank, N.A., as administrative agent, and the lenders party thereto, of approximately $40.0 million, and had drawn approximately $160.0 million.  On October 6, 2015, the Company’s borrowing base under its Credit Facility was decreased from $200 million to $120 million as part of the Company’s regularly scheduled semi-annual redetermination by its lender. The decrease in the borrowing base has resulted in the outstanding revolving credit facility balance exceeding the revised borrowing base by approximately $19.6 million as of November 6, 2015. Under the terms of the Credit Agreement, the Company is obligated to repay the deficiency in three monthly installments following the date of the redetermination. The Company does not expect to be able to make the monthly installments, which will result in a default under the Credit Agreement. Further, the previously announced term loan facility was not consummated and has had an adverse effect on the Company’s operations and liquidity. The Company and its advisors are negotiating with the bank group regarding a repayment schedule and continues to work with a group of term debt providers for a term debt solution. The Company believes it will need to complete certain transactions, including management of and/or refinancing of its debt capital structure and potential asset sales, to have sufficient liquidity to satisfy all of its obligations, including eliminating the approximate $19.6 million deficiency under the Credit Facility in the near term and obligations such as oil, natural gas and produced water transportation and processing commitments, fixed drilling commitments and operating leases, in the long term.

As a result of substantial declines in oil and gas prices during the latter half of 2014 and continuing into the first part of 2015, the liquidity outlook of the Company, including its working capital balance and EBITDA, has been impacted.  As a result, the Company expects lower operating cash flows than previously experienced and if commodity prices continue to remain low, the Company’s liquidity will be further impacted. In addition to the default regarding the deficiency repayments under the Credit Agreement described above, the Company was not in compliance with the total debt to EBITDA and Senior Secured Debt-to-EBITDA ratios under the Credit Facility as of September 30, 2015. The breach of the covenants under the Credit Facility could cause a default under the Credit Facility if not amended or waived by the lending group, and the lenders would be able to accelerate the maturity of the Credit Facility and exercise other rights and remedies. This, in turn, would cause a default under the Convertible Notes due in 2019 and permit the holders of those notes to accelerate their maturity. In accordance with the provisions under ASC 470-10-45-1, the Company has classified the balances of the Credit Facility and Convertible Notes as a current liability as of September 30, 2015. Furthermore, the ability to refinance any of the existing indebtedness on commercially reasonable terms may be materially and adversely impacted by the current conditions in the energy industry and the Company’s financial condition.

On November 5, 2015, the Company and certain of its subsidiaries entered into a forbearance agreement (the “Forbearance Agreement”) with the lenders party to the Credit Agreement. Pursuant to the Forbearance Agreement, the Lenders and the Agent agreed to forbear from exercising their rights and remedies under the Credit Agreement until December 18, 2015 (the “Forbearance Period”) with respect to certain events of default under the Credit Agreement. For additional information regarding the Forbearance Agreement, see Note 15 Subsequent Events— Forbearance Agreement.

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The commodity price decline has materially reduced the revenues that were generated from the sale of the Company’s oil and gas production volumes during that period, which, in turn, has negatively affected the Company’s working capital balance and EBITDA. The potential for future oil prices to remain at their current price levels for an extended period of time raises substantial doubt regarding the Company’s ability to continue as a going concern. For purposes of this discussion, the term “substantial doubt” refers to concerns that a company may not be able to meet its obligations when they come due. The accompanying financial statements do not include any adjustments related to the recoverability and classification of recorded assets or the amounts and classification of liabilities, other than classifying the outstanding balances of the Credit Facility and Convertible Notes as current liabilities, that might result from the uncertainty associated with the ability to meet obligations as they come due.

The Company continues to pursue a number of actions including (i) actively managing the debt capital structure, (ii) selling additional assets, (iii) minimizing capital expenditures, (iv) obtaining waivers or amendments from lenders, (v) effectively managing working capital and (vi) improving cash flows from operations. As previously noted, the Company has engaged financial advisors and other professionals to assist it with reviewing all options to improve its liquidity profile and strengthen its balance sheet. These efforts continue in earnest and the Company is considering all available strategic alternatives and financing possibilities, including, without limitation, the incurrence of additional secured indebtedness and the exchange or refinancing of existing obligations.  The Company can provide no assurance that these discussions will result in the completion of a transaction, or that any completed transaction will result in sufficient liquidity to satisfy the Company’s obligations.

NOTE 4  OIL AND NATURAL GAS PROPERTIES

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

Joint Venture Agreement

On July 31, 2015, the Company entered into a purchase and sale agreement with Koch Exploration Company, LLC (“Koch Exploration”), a wholly owned subsidiary of Koch Industries Inc. Subject to customary closing conditions, Koch Exploration acquired a 30% working interest in approximately 25,000 undeveloped net acres held by the Company in McKenzie County, North Dakota and approximately 4,400 undeveloped net acres held by the Company in Richland County, Montana for approximately $17.4 million. Koch Exploration reimbursed the Company approximately $5.4 million for its proportionate share of recently drilled and uncompleted wells in southern McKenzie County, North Dakota. Total proceeds to the Company upon closing the transaction were approximately $22.8 million and all proceeds were used to pay down outstanding borrowings under the Company’s Credit Facility (see Note 15 Subsequent Events – Joint Venture Agreement).

Acquisitions

On September 2, 2014, the Company acquired approximately 30,500 net acres located in McKenzie, Billings and Dunn Counties of North Dakota from an unrelated third party for approximately $71.2 million in cash and the assignment of approximately 4,300 net acres held by the Company in Williams County, North Dakota.

The following table summarizes the purchase price and estimated values of assets acquired and liabilities assumed for the September 2014 acquisition (in thousands):

Purchase Price
Consideration Given:
Cash	$	71,187
Assignment of oil and natural gas properties		35,918
Liabilities assumed, net		1,121
Total	$	108,226
Allocation of Purchase Price:
Proved oil and natural gas properties	$	48,997
Unproved oil and natural gas properties		59,083
Liabilities released		146
Total fair value of oil and natural gas properties	$	108,226

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Pro Forma Operating Results

In accordance with ASC Topic 805, presented below are unaudited pro forma results for the three and nine months ended September 30, 2014 to show the effect on our consolidated results of operations as if the September 2014 acquisition had occurred on January 1, 2013.

The pro forma results reflect the results of combining our statement of operations with the results of operations from the oil and natural gas properties acquired in September 2014, adjusted for (i) the assumption of asset retirement obligations and accretion expense for the properties acquired and (ii) depletion expense applied to the adjusted basis of the properties acquired. The pro forma information is based upon these assumptions and is not necessarily indicative of future results of operations:

	Three Months Ended September 30, 2014		Nine Months Ended September 30, 2014
Revenues	$	43,160,959	$	95,151,146
Net Income	$	14,860,956	$	14,723,060
Net Income Per Share – Basic	$	4.47	$	4.44
Net Income Per Share – Diluted	$	3.36	$	3.60
Weighted Average Shares Outstanding – Basic	$	3,324,970	$	3,316,470
Weighted Average Shares Outstanding – Diluted	$	4,419,020	$	4,093,377

NOTE 5  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”), 255,732 shares of Series B Voting Preferred Stock (“Series B Preferred Stock”) and warrants to purchase an initial aggregate amount of 255,732 shares of the Company’s common stock at an initial exercise price of $115.40 per share, for an aggregate $50 million. Pursuant to the Securities 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 during 2013, 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. On January 28, 2015, Mr. Edelman resigned from his position as a director of the Company and Ben Guill, a Managing Partner of White Deer Energy, was appointed to the Board of Directors. For additional information regarding the Securities Purchase Agreement with White Deer Energy, see Note 6 — 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 255,732 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 139,280 shares of Company common stock and 254,643 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 393,923 shares of common stock and 255,732 shares of common stock underlying the warrants held by White Deer Energy, and the SEC declared the registration statement effective on May 30, 2014. In February 2015, the Company completed a public offering of 1,357,955 shares of common stock at a price of $22.40 per share for total net proceeds of approximately $29.4 million. White Deer Energy purchased 669,643 common shares in the public offering. White Deer Energy’s participation in the public offering was approved by the Company’s board of directors.

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NOTE 6  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, 255,732 shares of Series B Preferred Stock and warrants to purchase an initial aggregate 255,732 shares of the Company’s common stock at an initial exercise price of $115.40 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 the $50,000,000 principal and redemption premiums of $6,250,000, and no shares of Series A Preferred Stock remained outstanding as of September 30, 2015. 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 nine months ended September 30, 2015 and 2014.

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 255,732 shares of common stock at an initial exercise price of $115.40 per share and surrendering an equal number of shares of Series B Preferred Stock to the Company. In December 2014, the Company issued 536,091 common shares below the initial warrant exercise price of $115.40 to extinguish $21,000,000 of its Convertible Notes. In February 2015, the Company completed a public offering of 1,357,955 shares of common stock at a price of $22.40 per share for total net proceeds of approximately $29.4 million. During April and May 2015, the Company issued an aggregate 2,460,045 shares of common stock through its at-the-market continuous offering program (“ATM program”) at an average price of $6.87 per share for total net proceeds of approximately $16.4 million. During September 2015, the Company issued an aggregate 848,961 shares of common stock through its ATM Program at an average price of $2.79 per share for total net proceeds of approximately $2.3 million. The sales were made pursuant to the terms of the equity distribution agreements dated April 2, 2015 between the Company and its sales agents. As a result of these issuances, the warrant exercise price was reduced from $16.45 to $9.52 per share pursuant to a formula provided in the original warrant agreement. See Note 9 – Convertible Notes for further discussion of the December 2014 conversion and Note 13 – Derivative Instruments and Price Risk Management – Warrant Liability for further discussion of the warrant liability valuation.

Upon a change of control or Liquidation Event, as defined in the Securities Purchase Agreement, White Deer Energy had the right to elect to receive from the Company, in exchange for all, but not less than all, securities issued pursuant to the Securities Purchase Agreement an additional cash payment necessary to achieve a minimum internal rate of return of 25% as calculated as defined. The calculation took into account all cash inflows from and cash outflows to White Deer Energy. Upon the final Series A Preferred Stock redemption on October 15, 2013, the minimum internal rate of return was achieved and no additional cash payment would be required to be paid to White Deer Energy upon a change of control or liquidation event.

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The Company recorded the transaction by recognizing the fair value of the Series A Preferred Stock at $38,552,994 (net of offering costs of $2,816,006), Series B Preferred Stock at $5,000 and a warrant liability of $8,626,000 at time of issuance. The Company 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 were probable. The Company recognized all issuance discount accretion related to the redemptions of preferred stock by October 15, 2013. There was no issuance discount remaining as of September 30, 2015 or December 31, 2014.

A summary of the preferred stock transaction components as of September 30, 2015, December 31, 2014 and the issuance date is provided below:

	September 30, 2015		December 31, 2014		February 19, 2013 (issuance date)
Series A Preferred Stock	$	—	$	—	$	41,369,000
Series B Preferred Stock		256		256		256
Warrant Liability		187,000		2,199,000		8,626,000
Total	$	187,256	$	2,199,256	$	49,995,256

Equity Issuances

On February 11, 2015, the Company completed a public offering of 1,357,955 shares of common stock at a price of $22.40 per share for total net proceeds of approximately $29.4 million.

During April and May 2015, the Company issued shares of common stock through its ATM Program totaling 2,460,045 at an average price of $6.87 per share for total net proceeds of approximately $16.4 million.  During September 2015, the Company issued shares of common stock through its ATM Program totaling 848,961 at an average price of $2.79 per share for total net proceeds of approximately $2.3 million. These sales were made pursuant to the terms of the equity distribution agreement dated April 2, 2015 between the Company and its sales agents.

Restricted Stock Awards and Restricted Stock Unit Awards

The Company incurred compensation expense associated with restricted stock and restricted stock units granted of $438,346 and $2,480,352 for the three months ended September 30, 2015 and 2014, respectively, and $2,444,623 and $8,686,625 for the nine months ended September 30, 2015 and 2014, respectively. As of September 30, 2015, there were 72,092 non-vested restricted stock units and $975,865 of associated remaining unrecognized compensation expense, which is expected to be recognized over the weighted-average period of 0.70 years. The Company capitalized compensation expense associated with the restricted stock and restricted stock units of $83,425 and $437,612 to oil and natural gas properties for the three months ended September 30, 2015 and 2014, respectively, and $601,605 and $1,425,364 for the nine months ended September 30, 2015 and 2014, respectively.

A summary of the restricted stock units and restricted stock shares activity during the nine months ended September 30, 2015 is as follows:

	Number of Shares			Weighted Average Grant Date Fair Value
Non-vested restricted stock and restricted stock units at January 1, 2015		29,231		$	145.40
Granted		52,217			15.50
Canceled		(3,961	)		14.33
Vested and forfeited for taxes		(1,358	)		149.60
Vested and issued		(4,037	)		149.60
Non-vested restricted stock and restricted stock units at September 30, 2015		72,092		$	57.78

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NOTE 7  STOCK OPTIONS AND WARRANTS

Stock Options

The Company granted no stock options during the nine months ended September 30, 2015.

The impact on the Company’s condensed consolidated statement of operations of stock-based compensation expense related to options granted for the three months ended September 30, 2015 and 2014 was $(15,200) and $337,809, respectively, net of forfeitures, cancellations and $0 tax. The impact on the Company’s condensed consolidated statement of operations of stock-based compensation expense related to options granted for the nine months ended September 30, 2015 and 2014 was $142,276 and $810,419, respectively, net of forfeitures, cancellations and $0 tax. The Company capitalized $(5,035), and $187,017 in compensation to oil and natural gas properties related to outstanding options for the three months ended September 30, 2015 and 2014, respectively, and $106,995 and $595,628  for the nine months ended September 30, 2015 and 2014, respectively. The Company had $183,140 of total unrecognized compensation cost related to nonvested stock options granted as of September 30, 2015. The remaining cost is expected to be recognized over a weighted-average period of 0.89 years. These estimates are subject to change based on a variety of future events that 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 nine months ended September 30, 2015 is as follows:

	Number of Options			Weighted Average Exercise Price
Balance outstanding at January 1, 2015		59,746		$	171.20
Granted		—			—
Canceled		(19,210	)		218.39
Exercised		—			—
Balance outstanding at September 30, 2015		40,536		$	148.78
Options exercisable at September 30, 2015		30,759		$	150.83

At September 30, 2015, 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
2015		—		—		—		—		—		—
2014		15,781		3.18	$	143.48		8,804		2.98	$	145.17
2013		8,755		3.36		140.95		5,955		2.92		139.27
2012		14,731		1.82		156.80		14,731		1.82		156.80
Prior		1,269		2.97		174.96		1,269		2.97		174.96
Total		40,536		2.72	$	148.78		30,759		2.41	$	150.83

Warrants

The table below reflects the status of warrants outstanding at September 30, 2015:

	Warrants		Exercise Price		Expiration Date
December 1, 2009		1,861	$	137.20	December 1, 2019
December 31, 2009		9,304	$	137.20	December 31, 2019
February 8, 2011		44,643	$	994.00	February 8, 2016
February 19, 2013		255,732	$	9.52	December 31, 2019
Total		311,540

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No warrants expired or were forfeited during the nine months ended September 30, 2015. All of the compensation expense related to the applicable vested warrants issued to employees has been expensed by the Company prior to 2012. All warrants outstanding were exercisable at September 30, 2015. See Note 13 – Derivative Instruments and Price Risk Management for details on the treatment of the warrants issued on February 19, 2013.

NOTE 8 REVOLVING CREDIT FACILITY

Wells Fargo Facility

On November 20, 2012, the Company entered into a senior secured revolving credit facility (as amended, the “Credit Facility”) with Wells Fargo Bank, N.A., as administrative agent (“Wells Fargo”), and the lenders party thereto. The Credit Facility is a senior secured reserve-based revolving credit facility with a maximum commitment of $400 million. On April 30, 2015, in connection with the semi-annual borrowing base redetermination, the Company and its lending group entered into an amendment to the Credit Facility. The amendment to the Credit Facility reduced the borrowing base from $250 million to $200 million. As of September 30, 2015, the Company had drawn approximately $160 million toward its $200 million borrowing base under the Credit Facility. The Company’s borrowing base under its Credit Facility was subject to its semi-annual redetermination on October 6, 2015, and the lenders decreased the borrowing base to $120 million. This redetermination resulted in an outstanding deficiency under the Credit Facility of approximately $19.6 million. Under the terms of the Credit Agreement, the Company is permitted to repay the deficiency in three monthly installments beginning 30 days after the date of the redetermination. The Company does not expect to be able to make the monthly installments, which will result in a default under the Credit Agreement. 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 5.0 to 1.0 for periods ending on March 31, 2015 through June 30, 2016 and 5.5 to 1.0 for periods ending September 30, 2016 through December 31, 2016 and (c) a Senior Secured Debt-to-EBITDA ratio for periods ending March 31, 2015 through December 31, 2016 of no more than 2.5 to 1.0. The Company was not in compliance with the total debt to EBITDA and Senior Secured Debt-to-EBITDA ratios under the Credit Facility as of September 30, 2015.

On November 5, 2015, the Company and certain of its subsidiaries entered into a Forbearance Agreement with the lenders party to the Credit Agreement. Pursuant to the Forbearance Agreement, the Lenders and the Agent agreed to forbear from exercising their rights and remedies under the Credit Agreement until December 18, 2015 with respect to certain events of defaults under the Credit Agreement. Please see Note 3 – Liquidity and Capital Resources and Note 15 – Subsequent Events – Forbearance Agreement for further information regarding changes to financing arrangements and changes to the Credit Facility subsequent to September 30, 2015.

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 under the Credit Facility, 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 September 30, 2015, the annual interest rate on the Credit Facility was 2.70%.

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 September 30, 2015, the Company has not obtained any letters of credit under the Credit Facility.

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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 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. As of September 30, 2015, the Company had hedges covering 70% of its projected production through 2016.

NOTE 9 CONVERTIBLE NOTES

On March 24, 2014, the Company completed a private placement of $172.5 million in aggregate principal amount of 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. As of September 30, 2015, 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 had a total outstanding principal balance of $151.5 million and were convertible into approximately 863,248 shares of common stock.

The net proceeds from the Convertible Notes were $166.9 million, after deducting commissions and 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 5.698 shares of the Company’s common stock per $1,000 principal amount of Convertible Notes (which represents a conversion price of approximately $175.60 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, including the acceleration of the maturity of the Credit Facility, which would, in turn, cause a default under the Indenture and permit the holders of the Convertible Notes to accelerate their maturity. 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 under the Indenture as of September 30, 2015; however, the Company was not in compliance with all covenants under the Credit Facility, and the lenders thereunder could declare a default, which if remained uncured, would allow the lenders under the Credit Facility to accelerate the maturity of the amounts outstanding under the Credit Facility. As of September 30, 2015, the Company had drawn approximately $160 million toward its $200 million borrowing base under the Credit Facility. The Company’s borrowing base under its Credit Facility was subject to its semi-annual redetermination on October 6, 2015, and the lenders decreased the borrowing base to $120 million. This redetermination resulted in an outstanding deficiency under the Credit Facility of approximately $19.6 million. Under the terms of the Credit Agreement, the Company is permitted to repay the deficiency in three monthly installments beginning 30 days after the date of the redetermination. The Company does not expect to be able to make the monthly installments, which will result in a default under the Credit Agreement. In accordance with the provisions under ASC 470-10-45-1, the Company has classified the balance of the Convertible Notes as a current liability as of September 30, 2015. On November 5, 2015, the Company and certain of its subsidiaries entered into a Forbearance Agreement with the lenders party to the Credit Agreement. Pursuant to the Forbearance Agreement, the Lenders agreed to forbear from exercising their rights and remedies under the Credit Agreement until December 18, 2015 with respect to certain events of defaults under the Credit Agreement. For additional information regarding the Forbearance Agreement, see Note 15 Subsequent Events— Forbearance Agreement.

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In December 2014, the Company issued 536,091 shares of common stock to extinguish $21,000,000 principal value of Convertible Notes. The Convertible Notes had 119,658 underlying shares of common stock under the terms of the Indenture. As a result, the Company recognized $10,438,080 of debt conversion expense for the year ended December 31, 2014 for the fair value of the shares of common stock issued in excess of the shares of common stock underlying the exchanged Convertible Notes. For details on the additional note conversion subsequent to September 30, 2015, see Note 15 – Subsequent Events – Debt Conversion.

NOTE 10  ASSET RETIREMENT OBLIGATION

The Company has asset retirement obligations associated with the future plugging and abandonment of its proved oil and natural gas properties and related facilities. Under the provisions of ASC 410-20-25, the fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred and can be reasonably estimated, 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) plugging and abandonment costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors (average of 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 nine months ended September 30, 2015 and the year ended December 31, 2014:

	Nine Months Ended September 30, 2015		Year Ended December 31, 2014
Beginning Asset Retirement Obligation	$	2,671,975	$	692,137
Revision of Previous Estimates		—		148,968
Liabilities Incurred or Acquired		440,536		1,817,939
Accretion of Discount on Asset Retirement Obligations		153,007		104,803
Wells Settled Through P&A		—		(72,555	)
Liabilities Associated with Properties Sold		—		(19,317	)
Ending Asset Retirement Obligation	$	3,265,518	$	2,671,975

NOTE 11  INCOME TAXES

Deferred income tax assets and liabilities are determined based upon differences between the financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse. Accounting standards require the consideration of a valuation allowance for deferred tax assets if it is “more likely than not” that some component or all of the benefits of deferred tax assets will not be realized. As of September 30, 2015 and December 31, 2014, 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 12 FAIR VALUE

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

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

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

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

The level in the fair value hierarchy within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The Company’s policy is to recognize transfer in and/or out of the 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 September 30, 2015:

	Fair Value Measurements at September 30, 2015 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	$	—	$	—		$	(187,000	)
Commodity Derivatives – Current Asset (oil puts)		—		14,310,070			—
Commodity Derivatives – Non Current Asset (oil puts)		—		3,442,664			—
Commodity Derivatives – Current Liability (oil put premiums)		—		(7,974,013	)		—
Commodity Derivatives – Long Term Liability (oil put premiums)		—		(2,067,594	)		—
Total	$	—	$	7,711,127		$	(187,000	)

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, 2014:

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	Fair Value Measurements at December 31, 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 Asset (Liability)	$	—	$	—	$	(2,199,000	)
Commodity Derivatives – Current Asset (oil swaps)		—		5,044,125		—
Total	$	—	$	5,044,125	$	(2,199,000	)

Level 2 assets consist of commodity derivative assets and liabilities (see Note 13 – Derivative Instruments and Price Risk Management). The fair value of the commodity derivative assets and liabilities are estimated by the Company using the income valuation techniques utilizing an option pricing or discounted cash flow model, as appropriate, that takes 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 condensed consolidated balance sheets.

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

Balance, at January 1, 2014	$	(15,703,000	)
Change in Fair Value of Warrant Liability		13,504,000
Balance, at December 31, 2014		(2,199,000	)
Change in Fair Value of Warrant Liability		2,012,000
Balance, at September 30, 2015	$	(187,000	)

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 gain was $221,000 and $216,000 for the three months ended September 30, 2015 and 2014, respectively, and $2,012,000 and $(1,751,000) for the nine months ended September 30, 2015 and 2014, respectively. The warrant revaluation gain (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 13 – Derivative Instruments and Price Risk Management.

Nonrecurring Fair Value Measurements

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

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

The Company’s non-derivative financial instruments include cash and cash equivalents, restricted cash, 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 $39.4 million at September 30, 2015 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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NOTE 13 DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT

Commodity Price Risk

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, both the current asset and liability and the non-current asset and liability are netted on the condensed consolidated balance sheet.

On January 5, 2015, the Company settled its outstanding NYMEX West Texas Intermediate oil derivative swap contracts on a total of 120,000 barrels of oil, resulting in the receipt of $5,317,300 in cash. On April 7, 2015, the Company entered into put option contracts for oil volumes produced in May 2015 through December 2016, whereby premiums are paid monthly throughout the life of the contracts. Open contracts as of September 30, 2015 are provided in the table below.

Settlement Period	Daily Volume Oil (Bbls)		Put Option Fixed Price Per Bbl		Total Volume (Bbls)		Premium Paid Per Bbl		Total Premiums Due
October 2015 – December 2015		4,000	$	55.00		368,000	$	4.88	$	1,795,840
January 2016 – December 2016		3,000	$	60.00		1,098,000	$	7.54	$	8,278,920

The following table sets forth a reconciliation of the changes in fair value of the Company’s commodity derivatives for the three and nine months ended September 30, 2015 and 2014.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Beginning fair value of commodity derivatives	$	(3,633,216	)	$	(5,852,801	)	$	5,044,125		$	(853,005	)
Total gains on commodity derivatives		12,699,147			11,184,716			8,148,386			3,722,780
Cash settlements (received) paid on commodity derivatives		(1,354,804	)		313,451			(5,481,384	)		2,775,591
Ending fair value of commodity derivatives	$	7,711,127		$	5,645,366		$	7,711,127		$	5,645,366

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 its counterparties that provide for offsetting payables against receivables from separate derivative instruments.

Warrant Liability

The warrants issued to White Deer Energy are classified as liabilities on the consolidated balance sheets because the warrants contain a contingent put and other liability type provisions (see Note 6 – Preferred and Common Stock). The shares of common stock 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 condensed consolidated statements of operations.

The Company estimated the value of the warrants issued on the date of issuance to be $8,626,000, or $33.80 per warrant, using the Monte Carlo model with the following assumptions: a term of 1,798 trading days, exercise price of $115.40, volatility rate of 40%, and a risk-free interest rate of 1.38%. The Company remeasured the warrants as of September 30, 2015, using a Black-Scholes model with the following assumptions: a term of 1,067 trading days, exercise price of $9.52, a 15-day volume weighted average stock price of $2.34, volatility rate of 80%, and a risk-free interest rate of 1.65%. As of September 30, 2015, the fair value of the warrants was $187,000, and was recorded as a liability on the accompanying condensed consolidated balance sheet. 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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NOTE 14 COMMITMENTS AND CONTINGENCIES

Executive Compensation

In January 2015, the Company determined that fifty percent of the earned cash bonuses for 2014 for the Chief Executive Officer and Vice Chairman of the Board of Directors would be paid in the form of equity and that such 50 percent (payable in the form of equity) would be paid by early 2016. Additionally, the Company determined that fifty percent of the annual equity bonus would be granted in early 2016.

After discussions with the Compensation Committee relating to the foregoing payments, each of the officers agreed in principle not to allege a violation of their respective employment agreements if the bonuses were paid in accordance with the foregoing.

Oil, Natural Gas and Produced Water Transportation and Processing Commitments. 

The Company has commitments for the transportation and processing of its production on certain wells within its operating area in the Williston Basin of North Dakota, including an aggregate minimum commitment to deliver on a gross basis 16.4 MMBbls of oil at a fee of $1.21/Bbl, 10.9 Bcf of natural gas at a fee of $1.67/Mcf and 28.2 MMBbls of produced water at a fee of $0.82/Bbl through April 2020. The Company is required to make monthly deficiency payments for any shortfalls in delivering the minimum volumes under these commitments. Currently, the Company has insufficient production to meet these contractual commitments. However, as the Company develops additional reserves, it anticipates exceeding its current minimum volume commitments and, therefore, intends to enter into additional transportation and processing commitments in the future. The commitment price can be adjusted in future years. These future transportation and processing commitments may expose the Company to additional volume deficiency payments. For the three months ended September 30, 2015, the Company incurred deficiency fees of $1.0 million and expects to continue to accrue deficiency fees under its commitments as long as the Company’s development program is suspended. The deficiency fees are included as production expenses in the statement of operations for the three and nine months ended September 30, 2015. Transportation costs aside from the deficiency fee are included in the realized price of oil and natural gas revenues in the statement of operations for the three and nine months ended September 30, 2015. Estimated future deficiency fees are included in the calculation of the present value of estimated future net revenues from proved oil and natural gas reserves, which impacts the ceiling test impairment calculation.

Other

The Company is involved in various matters incidental to its operations and business that might give rise to a loss contingency.  These matters may include legal and regulatory proceedings, commercial disputes, claims from royalty, working interest and surface owners, property damage and personal injury claims and environmental authorities or other matters. In addition, the Company may be subject to customary audits by governmental authorities regarding the payment and reporting of various taxes, governmental royalties and fees as well as compliance with unclaimed property (escheatment) requirements and other laws.  Further, other parties with an interest in wells operated by the Company have the ability under various contractual agreements to perform audits of its joint interest billing practices. The Company vigorously defends itself in these matters.  If the Company determines that an unfavorable outcome or loss of a particular matter is probable and the amount of the loss can be reasonably estimated, it accrues a liability for the contingent obligation. As new information becomes available or as a result of legal or administrative rulings in similar matters or a change in applicable law, the Company’s conclusions regarding the probability of outcomes and the amount of estimated loss, if any, may change. The impact of subsequent changes to the Company’s accruals could have a material effect on its results of operations.

NOTE 15 SUBSEQUENT EVENTS

Joint Venture Agreement

On October 1, 2015, the Company closed the purchase and sale agreement with Koch Exploration. Subject to customary closing conditions, Koch Exploration acquired a 30% working interest in approximately 25,000 undeveloped net acres held by the Company in McKenzie County, North Dakota and approximately 4,400 undeveloped net acres held by the Company in Richland County, Montana for approximately $17.4 million. Koch Exploration reimbursed the Company approximately $5.4 million for its proportionate share of recently drilled and uncompleted wells in southern McKenzie County, North Dakota. Total proceeds to the Company upon closing the transaction were approximately $22.8 million and all proceeds were used to repay outstanding borrowings on the Credit Facility, reducing the outstanding balance from $160 million to $139.6 million subsequent to September 30, 2015.

Borrowing Base Redetermination

On October 6, 2015 the Company’s borrowing base under the Credit Facility was decreased from $200 million to $120 million as part of the Company’s regularly scheduled semi-annual redetermination by its lenders. The decrease in the borrowing base resulted in the outstanding balance of the Credit Facility to exceed the revised borrowing base by approximately $19.6 million as of November 6, 2015 (See Note 8 – Revolving Credit Facility).

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Forbearance Agreement

On November 5, 2015, the Company, along with certain of its subsidiaries (the “Guarantors”), entered into a forbearance agreement (the “Forbearance Agreement”) with the lenders (the “Lenders”) party to the Credit Agreement, and Wells Fargo Bank, N.A., as agent for the Lenders (the “Agent”). Pursuant to the Forbearance Agreement, the Lenders and the Agent agreed to forbear from exercising their rights and remedies under the Credit Agreement until December 18, 2015 (the “Forbearance Period”) with respect to certain events of defaults under the Credit Agreement (the “Specified Defaults”).

The Forbearance Period will terminate immediately upon the occurrence of any of the following: (i) a default under the Credit Agreement other than the Specified Defaults; (ii) any misrepresentation by the Company or any of the Guarantors under the Forbearance Agreement; (iii) the failure of the Company or any of the Guarantors to perform, observe or comply with the terms of the Forbearance Agreement; (iv) the commencement of any bankruptcy, insolvency or similar proceeding against the Company or any of the Guarantors or the appointment of a trustee or similar official for the Company or any of the Guarantors or a substantial part of its property; (v) any default in excess of $5,000,000 under certain specified material contracts; or (vi) any event during the Forbearance Period which has a Material Adverse Effect (as defined in the Credit Agreement).

In exchange for the Lenders and the Agent agreeing to forbear their rights and remedies under the Credit Agreement, the Company has agreed during the Forbearance Period to, among other things: (i) make monthly interest payments at the Alternate Base Rate (as defined in the Credit Agreement) plus 1.75%; (ii) pay the Lenders a fee equal to 0.50% of the outstanding principal balance of the loans under the Credit Agreement; (iii) use 100% of the Net Cash Proceeds (as defined in the Credit Agreement) received by the Company or any Guarantor to make mandatory prepayments of the loans under the Credit Agreement in certain circumstances; (iv) periodically deliver to the Agent and the Lenders certain financial and budget information; (v) cause unrestricted cash and cash equivalents to not be less than $1,000,000 at the end of each week; and (vi) limit capital expenditures to $300,000.

The foregoing description of the Forbearance Agreement is a summary only and is qualified in its entirety by reference to the Forbearance Agreement, a copy of which is attached as Exhibit 10.3 to this Quarterly Report on Form 10-Q and incorporated herein by reference.

Debt Conversion

On October 22, 2015, the Company entered into an agreement with a holder of the Convertible Notes pursuant to which the Company and the noteholder agreed to exchange approximately $3 million principal value of Convertible Notes for a number of shares of common stock to be issued based upon a formula that utilizes a 15% discount to the volume weighted average price of the Company’s common stock over a period of 15 consecutive trading days starting October 23, 2015 and ending on approximately November 12, 2015, which is expected to be approximately 880,000 shares of common stock based on an average estimated price of approximately $1.70 per common share. As a result, the Company expects to recognize approximately $1.5 million of debt conversion expense for the fair value of the shares of common stock issued in excess of the shares of common stock underlying the original convertible note indenture agreement. Following the completion of the exchange, approximately $148.5 million aggregate principal amount of the Convertible Notes will remain outstanding.

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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, 2014 and in our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2015 and June 30, 2015 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, which is largely dependent upon oil and natural gas commodity prices.

Our Williston Basin acreage is located primarily in McKenzie, Billings and Stark Counties of North Dakota and Richland County of Montana. Our primary geologic target is the Bakken Pool where our primary objective is the dolomitic, sandy interval between the two Bakken Shales at an approximate vertical depth of 10,600 – 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.

Assets and Acreage Holdings

As of September 30, 2015, we held approximately 86,000 net acres in the Williston Basin pro forma for the acreage sale closed on October 1, 2015. We operate approximately 73,000 net acres, or 85% 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;

· 23,000 net acres in the Lewis & Clark area of McKenzie County, North Dakota south of the Low Rider area.

· 5,000 net acres in the Pronghorn Sand formation in Stark and Billings Counties, North Dakota in the core of the Pronghorn field; and

· 1,000 net acres in the Richland area of Richland County, Montana;

2015 Capital Development Plan

Our capital expenditures budget for 2015 is $75.0 million, of which $72.0 million is expected to fund the drilling of 7.5 net wells operating one drilling rig, and $3.0 million to fund leasehold acquisitions, all in the Williston Basin of North Dakota and Montana. With regard to the $72 million in capital expenditures and the associated drilling plans for 2015, $36 million of these capital expenditures will be directed to the conversion of proved undeveloped reserves, primarily related to completing wells drilled in 2014. We incurred $7.3 million in total capital costs during the third quarter of 2015, which were primarily attributable to the completion of three gross (3.0 net) wells during the quarter. Due to significantly lower oil and natural gas commodity prices, we have suspended our development plan for at least the remainder of 2015. We have incurred $75.5 million of drilling and completion costs toward our total 2015 capital expenditure budget through the first nine months of 2015. As of September 30, 2015, there are no wells completing or awaiting completion. We are subject to a $300,000 capital expenditure budget restriction through the Forbearance Period (see Recent Developments – Forbearance Agreement below) and expect to incur no capital development costs during the remainder of 2015 other than infrastructure, facilities or field transportation costs.

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Recent Developments

Amendment to the Credit Facility

As of September 30, 2015, we had drawn approximately $160 million toward the $200 million borrowing base under the Credit Facility. On October 6, 2015, our lenders under the Credit Facility decreased the borrowing base from $200 million to $120 million as part of our regularly scheduled semi-annual redetermination. The decrease in the borrowing base resulted in the outstanding balance of the Credit Facility to exceed the revised borrowing base by approximately $19.6 million as of November 6, 2015. Under the terms of the Credit Agreement, we are permitted to repay the deficiency in three monthly installments beginning 30 days after the date of the redetermination. We do not expect to be able to make the monthly installments, which will result in a default under the Credit Agreement. (See “Note 8 – Revolving Credit Facility” in the notes to the consolidated financial statements included in Part I, Item 1 of this Quarterly Report).

Forbearance Agreement

On November 5, 2015, we, along with certain of our subsidiaries (the “Guarantors”), entered into a Forbearance Agreement with the lenders (the “Lenders”) party to the Credit Agreement, and Wells Fargo Bank, N.A., as agent for the Lenders (the “Agent”). Pursuant to the Forbearance Agreement, the Lenders and the Agent agreed to forbear from exercising their rights and remedies under the Credit Agreement until December 18, 2015 (the “Forbearance Period”) with respect to certain events of defaults under the Credit Agreement (the “Specified Defaults”).

The Forbearance Period will terminate immediately upon the occurrence of any of the following: (i) a default under the Credit Agreement other than the Specified Defaults; (ii) any misrepresentation by us or any of the Guarantors under the Forbearance Agreement; (iii) the failure by us or any of the Guarantors to perform, observe or comply with the terms of the Forbearance Agreement; (iv) the commencement of any bankruptcy, insolvency or similar proceeding against us or any of the Guarantors or the appointment of a trustee or similar official for us or any of the Guarantors or a substantial part of our property; (v) any default in excess of $5,000,000 under certain specified material contracts; or (vi) any event during the Forbearance Period which has a Material Adverse Effect (as defined in the Credit Agreement).

In exchange for the Lenders and the Agent agreeing to forbear their rights and remedies under the Credit Agreement, we have agreed during the Forbearance Period to, among other things: (i) make monthly interest payments at the Alternate Base Rate (as defined in the Credit Agreement) plus 1.75%; (ii) pay the Lenders a fee equal to 0.50% of the outstanding principal balance of the loans under the Credit Agreement; (iii) use 100% of the Net Cash Proceeds (as defined in the Credit Agreement) received by us or any Guarantor to make mandatory prepayments of the loans under the Credit Agreement in certain circumstances; (iv) periodically deliver to the Agent and the Lenders certain financial and budget information; (v) cause unrestricted cash and cash equivalents to not be less than $1,000,000 at the end of each week; and (vi) limit capital expenditures to $300,000.

Joint Venture Agreement

On October 1, 2015, we closed a purchase and sale agreement with Koch Exploration. Subject to customary closing conditions, Koch Exploration acquired a 30% working interest in approximately 25,000 undeveloped net acres held by us in McKenzie County, North Dakota and 4,400 undeveloped net acres in Richland County, Montana for approximately $17.4 million. Koch Exploration reimbursed us approximately $5.4 million for its proportionate share of recently drilled and uncompleted wells in southern McKenzie County, North Dakota. At closing, we received approximately $22.8 million in total proceeds, and all proceeds were used to reduce outstanding borrowings on the Credit Facility. 

In conjunction with the transaction, we and Koch Exploration entered into a drilling agreement whereby we have agreed to drill two wells in 2016 in southern McKenzie County, North Dakota on two undeveloped drilling spacing units to further delineate the acreage position. An area of mutual interest (“AMI”) was established as part of the agreement so that when acreage is acquired by either us or Koch Exploration within the AMI in the future, the leasehold and costs will be split evenly between us.

Finance Update

During September 2015, we issued shares of common stock through our ATM Program totaling 848,961 at an average price of $2.79 per share for total net proceeds of approximately $2.3 million. These sales were made pursuant to the terms of the equity distribution agreements dated April 2, 2015 between us and our sales agents.

23

Productive Wells

The following table summarizes gross and net productive operated and non-operated oil wells at September 30, 2015 and September 30, 2014. A net well represents our fractional working ownership interest of a gross well. There were no wells in the process of being drilled, awaiting completion, in the process of completion or awaiting flow back as of September 30, 2015. The following table does not include 18 gross (14.6 net) operated Bakken and Three Forks wells and 4 gross (1.84 net) non-operated Bakken wells that were in the process of being drilled, awaiting completion, in the process of completion or awaiting flow back subsequent to fracture stimulation as of September 30, 2014.

	September 30,
	2015(2)				2014
	Gross		Net		Gross		Net
North Dakota Bakken and Three Forks – operated		60		47.72		36		26.6
North Dakota acquired production – operated (1)		43		36.01		43		33.5
Bakken and Three Forks – non-operated		48		5.46		40		3.6
Total		151		89.19		119		63.7

(1)

11 gross (7.90 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. 22 gross (19.90 net) wells relate to producing properties included within the acquisition completed on September 2, 2014 and the wells are producing from the Bakken formation. Operatorship was transferred to us upon closing of all acquisitions.

(2)

Does not include 3 gross (0.69 net) wells that were assigned to Koch Exploration pursuant to the purchase and sale agreement described above (See Recent Developments – Joint Venture Agreement).

Results of Operations

Comparison of the Three Months Ended September 30, 2015 with the Three Months Ended September 30, 2014

	Three Months Ended September 30,
	2015			2014
REVENUES
Oil Sales	$	17,350,524		$	28,266,332
Natural Gas Sales		494,804			460,857
Net Losses on Commodity Derivatives		12,699,147			11,184,716
		30,544,475			39,911,905
OPERATING EXPENSES
Production Expenses		8,201,949			6,962,450
Production Taxes		1,653,989			3,142,998
General and Administrative Expenses		3,821,473			5,483,655
Depletion of Oil and Natural Gas Properties		11,242,324			9,193,566
Impairment of Oil and Natural Gas Properties		158,278,000			—
Depreciation and Amortization		232,350			104,465
Accretion of Discount on Asset Retirement Obligations		52,500			28,037
Standby Rig Expense		3,800,446			—
Total Operating Expenses		187,283,031			24,915,171
INCOME (LOSS) FROM OPERATIONS		(156,738,556	)		14,996,734
OTHER EXPENSE, NET		(2,514,067	)		(1,337,659	)
INCOME (LOSS) BEFORE INCOME TAXES		(159,252,623	)		13,659,075
INCOME TAX EXPENSE		—			—
NET INCOME (LOSS)	$	(159,252,623	)	$	13,659,075

24

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 September 30,
	2015			2014
Net Oil and Natural Gas Revenues:
Oil	$	17,350,524		$	28,266,332
Natural Gas and Other Liquids		494,804			460,857
Total Oil and Natural Gas Sales		17,845,328			28,727,189
Net Gains on Commodity Derivatives		12,699,147			11,184,716
Total Revenues		30,544,475			39,911,905
Oil Derivative Net Cash Settlements (Received) Paid		(1,354,804	)		313,451
Net Production:
Oil (Bbl)		496,829			338,352
Natural Gas and Other Liquids (Mcf)		158,240			80,417
Barrel of Oil Equivalent (Boe)		523,202			351,755
Average Sales Prices:
Oil (per Bbl)	$	34.92		$	83.54
Effect of Settled Oil Derivatives on Average Price (per Bbl)		2.73			(0.93	)
Oil Net of Settled Derivatives (per Bbl)	$	37.65		$	82.61
Natural Gas and Other Liquids (per Mcf)	$	3.13		$	5.73
Barrel of Oil Equivalent with Net Cash Settlements Paid on Commodity Derivatives (per Boe)	$	36.70		$	80.78

Production costs incurred, presented on a per Boe basis, for the three months ended September 30, 2015 and 2014 are summarized in the following table:

	Three Months Ended September 30,
	2015		2014
Costs and Expenses Per Boe of Production:
Production Expenses	$	12.96	$	12.70
Workover Expenses		2.71		7.10
Total Production Expenses		15.68		19.80
Production Taxes		3.16		8.94
G&A Expenses (Excluding Non-Cash Stock-Based Compensation)		6.50		7.58
Non-Cash Stock-Based Compensation		0.81		8.01
Depletion of Oil and Natural Gas Properties		21.49		26.14
Impairment of Oil and Natural Gas Properties		302.52		—
Depreciation and Amortization		0.44		0.30
Accretion of Discount on Asset Retirement Obligation		0.10		0.08
Standby Rig Expense		7.26		—

Revenues

Revenues from sales of oil and natural gas were $17.8 million for the third quarter of 2015 compared to $28.7 million for the third quarter of 2014. Our total production volumes on a Boe basis increased 49% from 351,755 Boe to 523,202 Boe in the third quarter of 2015 as compared to the third quarter of 2014. Production increased primarily due to the addition of 21.12 net productive operated Bakken/Three Forks wells since October 1, 2014. Total revenues decreased in 2015 compared to 2014 due to lower realized commodity prices during 2015. During the third quarter of 2015, we realized a $37.65 average price per Bbl of oil (including settled derivatives) compared to an $82.61 average price per Bbl of oil during the third quarter of 2014.

25

Net Gains on Commodity Derivatives

Net gains on commodity derivatives were $12,699,147 during the third quarter of 2015 compared to $11,184,716 in the third quarter of 2014. Net cash settlements received (paid) on commodity derivatives were $1,354,804 in the third quarter of 2015 compared to $(313,451) in the third quarter of 2014. On April 7, 2015, we entered into put option contracts for oil volumes produced from May 2015 through December 2016, whereby we are obligated to pay monthly premiums throughout the life of the contracts. For further details on our open put contracts, please refer to Note 13 – Derivative Instruments and Price Risk Management in the notes to the consolidated financial statements included in Part I, Item 1 of this Quarterly Report. 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 September 30, 2015 and 2014, all of our derivative contracts were recorded at their fair value, which were net assets of $7,711,127 and $5,645,366, respectively.

Production Expenses

Production expenses were $8,201,949 for the third quarter of 2015 compared to $6,962,450 for the third quarter of 2014. Workover expenses totaling $1,419,335 were incurred in the third quarter of 2015 compared to $2,496,060 in the third quarter of 2014. The decrease of $1,076,725 in workover expenses is primarily attributable to producing properties acquired during 2014 that required significant workover activities. This increase in production expenses in 2015 compared to 2014 was primarily due to a $972,950 increase in water disposal costs associated with wells scheduled to have been connected to takeaway infrastructure in 2015, a $588,123 increase in equipment rental costs, a $521,272 increase in maintenance and repairs and a $331,586 increase in costs associated with regulatory compliance regarding natural gas capture and emissions. We experience increases in production expenses as we add new wells and maintain production from existing properties. On a per unit basis, production expenses slightly increased from $12.70 per Boe sold in the third quarter of 2014 compared to $12.96 per Boe for the third quarter of 2015 when excluding workover costs.

Production Taxes

Production taxes were $1,653,989 for the third quarter of 2015 compared to $3,142,998 for the third quarter of 2014. We pay production taxes based on realized oil and natural gas sales. Our average production tax rates were 9.3% for the third quarter of 2015 compared to 10.9% for the third quarter of 2014. 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 2015 average production tax rate was lower than 2014 due to an oil extraction tax incentive in North Dakota for wells completed between February and June 2015.

General and Administrative Expense

General and administrative expenses were $3,821,473 during the third quarter of 2015 compared to $5,483,655 during the third quarter of 2014. The decrease of $1,662,182 is primarily due to lower employee compensation and employee-related expenses. Employee compensation and employee-related expenses decreased on a period-over-period basis in 2015 compared to 2014 by $2,094,602 due primarily to lower executive compensation. Stock-based compensation expenses are included in employee compensation and related expenses, totaling $423,145 in the third quarter of 2015 compared to $2,775,788 in the third quarter of 2014.

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 $11,242,324 during the third quarter of 2015 compared to $9,193,566 during the third quarter of 2014. On a per-unit basis, depletion expense was $21.49 per Boe during the third quarter of 2015 compared to $26.14 per Boe during the third quarter of 2014. 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 decrease in depletion expense during the third quarter of 2015 on a per unit basis was due primarily to a lower depletable base as a result of the impairment expense recognized in 2015.

26

Impairment of Oil and Natural Gas Properties

We follow the full cost method of accounting for oil and natural gas operations whereby all costs related to the exploration and development of oil and natural gas properties are initially capitalized into a single cost center. Capitalized costs (net of related deferred income taxes) are limited to a ceiling based on the present value of future net revenues using the 12-month unweighted average of first-day-of-the-month price (the “12-month average price”), discounted at 10%, plus the lower of cost or fair market value of unproved properties. If the ceiling is not greater than or equal to the total capitalized costs, then we are required to write down capitalized costs to the ceiling. We perform this ceiling test calculation each quarter. Any required write downs are included in the condensed consolidated statements of operations as an impairment charge.

We recognized $158,278,000 of impairment expense in the third quarter of 2015 compared to $0 in the third quarter of 2014. The impairment expense is primarily due to the reduction in the price of crude oil beginning in the fourth quarter of 2014.

If commodity prices remain at decreased levels, the 12-month average price used in the ceiling calculation will decline and will likely cause additional write downs of our oil and natural gas properties. Continued write downs of oil and natural gas properties may occur until such time as commodity prices have recovered, and remained at recovered levels, so as to meaningfully increase the 12-month average price used in the ceiling calculation. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

Standby Rig Expense

Standby rig expenses totaled $3,800,446 for the third quarter of 2015. We are required to pay for idle time when our remaining rig is unutilized. The remaining drilling rig contract expires on October 31, 2015. We incurred no standby rig expense prior to 2015. Fees related to unutilized frac water commitments are included in standby rig expense, totaling $1,764,545 for the third quarter of 2015. We incurred no fees related to unutilized frac water commitments prior to 2015.

Other Expense, Net

Other expense, net was $2,514,067 for the third quarter of 2015 compared to $1,337,659 for the third quarter of 2014. We recognized a gain of $221,000 on the warrant liability for the third quarter of 2015 compared to a gain of $216,000 for the third quarter of 2014. 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 $2,735,348 for the third quarter of 2015, compared to $1,206,571 for the third quarter of 2014. The increase in interest expense primarily relates to the balance outstanding on the Credit Facility and increased amortization of debt issuance costs.

Net Loss

We had net loss of $159,252,623 for the third quarter of 2015 compared to net income of $13,659,075 for the third quarter of 2014 (representing ($19.85) and $4.11 per basic share, respectively). The resulting net loss, compared to net income in our period-over-period results, was driven by the impairment expense on our oil and natural gas properties, increased production expenses and lower revenues resulting from lower commodity prices.

Comparison of the Nine Months Ended September 30, 2015 with the Nine Months Ended September 30, 2014

	Nine Months Ended September 30,
	2015			2014
REVENUES
Oil Sales	$	52,981,871		$	76,989,268
Natural Gas Sales		1,224,667			2,061,201
Net Gains on Commodity Derivatives		8,148,386			3,722,780
		62,354,924			82,773,249
OPERATING EXPENSES
Production Expenses		25,972,453			13,477,176
Production Taxes		5,488,364			8,632,608
General and Administrative Expenses		12,495,471			21,609,218
Depletion of Oil and Natural Gas Properties		31,622,386			24,071,676
Impairment of Oil and Natural Gas Properties		304,903,000			—
Depreciation and Amortization		559,139			251,722
Accretion of Discount on Asset Retirement Obligations		153,007			63,837
Standby Rig Expense		6,173,111			—
Total Operating Expenses		387,366,931			68,106,237
INCOME (LOSS) FROM OPERATIONS		(325,012,007	)		14,667,012
OTHER EXPENSE, NET		(5,032,362	)		(4,609,075	)
INCOME (LOSS) BEFORE INCOME TAXES		(330,044,369	)		10,057,937
INCOME TAX EXPENSE		—			—
NET INCOME (LOSS)	$	(330,044,369	)	$	10,057,937

27

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.

	Nine Months Ended September 30,
	2015			2014
Net Oil and Natural Gas Revenues:
Oil	$	52,981,871		$	76,989,268
Natural Gas and Other Liquids		1,224,667			2,061,201
Total Oil and Natural Gas Sales		54,206,538			79,050,469
Net Gains on Commodity Derivatives		8,148,386			3,722,780
Total Revenues		62,354,924			82,773,249
Oil Derivative Net Cash Settlements (Received) Paid		(5,481,384	)		2,775,591
Net Production:
Oil (Bbl)		1,321,536			876,947
Natural Gas and Other Liquids (Mcf)		476,877			246,195
Barrel of Oil Equivalent (Boe)		1,401,016			917,980
Average Sales Prices:
Oil (per Bbl)	$	40.09		$	87.79
Effect of Settled Oil Derivatives on Average Price (per Bbl)		4.15			(3.17	)
Oil Net of Settled Derivatives (per Bbl)	$	44.24		$	84.62
Natural Gas and Other Liquids (per Mcf)	$	2.57		$	8.37
Barrel of Oil Equivalent with Net Cash Settlements Paid on Commodity Derivatives (per Boe)	$	42.60		$	83.09

Production costs incurred, presented on a per Boe basis, for the nine months ended September 30, 2015 and 2014 are summarized in the following table:

28

	Nine Months Ended September 30,
	2015		2014
Costs and Expenses Per Boe of Production:
Production Expenses	$	14.93	$	11.38
Workover Expenses		3.61		3.30
Total Production Expenses		18.54		14.68
Production Taxes		3.92		9.40
G&A Expenses (Excluding Non-Cash Stock-Based Compensation)		7.07		13.19
Non-Cash Stock-Based Compensation		1.85		10.35
Depletion of Oil and Natural Gas Properties		22.57		26.22
Impairment of Oil and Natural Gas Properties		217.63		—
Depreciation and Amortization		0.40		0.27
Accretion of Discount on Asset Retirement Obligation		0.11		0.07
Standby Rig Expense		4.41		—

Revenues

Revenues from sales of oil and natural gas were $54.2 million for the first nine months of 2015 compared to $79.1 million for the first nine months of 2014. Our total production volumes on a Boe basis increased 53% from 917,980 Boe in the first nine months of 2014 to 1,401,016 Boe in the first nine months of 2015. Production increased primarily due to the addition of 21.12 net productive operated Bakken/Three Forks wells since October 1, 2014. Total revenues decreased in 2015 compared to 2014 due to lower realized commodity prices during 2015. During the first nine months of 2015, we realized an $44.24 average price per Bbl of oil (including settled derivatives) compared to an $84.62 average price per Bbl of oil during the first nine months of 2014.

Net Gains on Commodity Derivatives

Net gains on commodity derivatives were $8,148,386 during the first nine months of 2015 compared to $3,722,780 in the first nine months of 2014. Net cash settlements received (paid) on commodity derivatives were $5,481,384 received in the first nine months of 2015 compared to $(2,775,591) paid in the first nine months of 2014. We settled certain swap contracts early in January 2015, resulting in approximately $5,317,300 in cash settlements received. On April 7, 2015, we entered into put option contracts for oil volumes produced in May 2015 through December 2016, whereby we are obligated to pay monthly premiums throughout the life of the contracts. For further details on our open put contracts, please see Note 13 – Derivative Instruments and Price Risk Management in the notes to the consolidated financial statements included in Part I, Item 1 of this Quarterly Report. 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 September 30, 2015 and 2014, all of our derivative contracts were recorded at their fair value, which were net assets of $7,711,127 and $5,645,366, respectively.

Production Expenses

Production expenses were $25,972,453 for the first nine months of 2015 compared to $13,477,176 for the first nine months of 2014. Workover expenses totaling $5,060,869 were incurred in the first nine months of 2015 compared to $3,029,085 in the first nine months of 2014. The increase is primarily due to workover rig charges of $1,963,740, artificial lift expenses of $795,892, equipment rental and supervision expenses of $847,746 and tubing and rod replacements of $389,584. We experience increases in production and workover expenses as we add new wells and maintain production from existing properties and well count was higher by 25.5 net wells (40% increase) compared to the same prior year period. On a per unit basis, production expenses increased from $14.68 per Boe in the first nine months of 2014 compared to $18.54 per Boe for the first nine months of 2015 when including workover costs. This increase in production expenses in 2015 compared to 2014 was primarily due to a $2,468,654 increase in water disposal costs associated with wells scheduled to have been connected to takeaway infrastructure in 2015, a $2,433,183 increase in equipment rental costs, a $1,684,535 increase in maintenance and repairs, a $1,344,415 increase in well servicing, and field supervision expenses and a $1,360,522 increase in costs associated with regulatory compliance regarding natural gas capture and emissions.

Production Taxes

Production taxes were $5,488,364 for the first nine months of 2015 compared to $8,632,608 for the first nine months of 2014. We pay production taxes based on realized oil and natural gas sales. Our average production tax rates were 10.1% for the first nine months of 2015 compared to 10.9% for the first nine months of 2014. 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 2015 average production tax rate was lower than 2014 due to an oil extraction tax incentive in North Dakota for wells completed between February and June 2015.

29

General and Administrative Expense

General and administrative expenses were $12,495,471 during the first nine months of 2015 compared to $21,609,218 during the first nine months of 2014. The decrease of $9,113,747 is primarily due to lower employee compensation and employee-related expenses. Employee compensation and employee-related expenses decreased on a period-over-period basis in 2015 compared to 2014 by $9,766,513 due primarily to lower executive compensation, offset by an increase of $698,924 related to insurance and legal expense due to increased financing activity during 2015. Stock-based compensation expenses are included in the employee compensation and related expenses, totaling $2,586,898 in the first nine months of 2015 compared to $9,364,171 in the first nine months of 2014.

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 $31,622,386 during the first nine months of 2015 compared to $24,071,676 during the first nine months of 2014. On a per-unit basis, depletion expense was $22.57 per Boe during the first nine months of 2015 compared to $26.22 per Boe during the first nine months of 2014. 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 decrease in depletion expense during the first nine months of 2015 compared to the first nine months of 2014 on a per unit basis was due primarily to a lower depletable base as a result of the impairment expense recognized in 2015.

Impairment of Oil and Natural Gas Properties

We follow the full cost method of accounting for oil and natural gas operations whereby all costs related to the exploration and development of oil and natural gas properties are initially capitalized into a single cost center. Capitalized costs (net of related deferred income taxes) are limited to a ceiling based on the present value of future net revenues using the 12-month unweighted average of first-day-of-the-month price (the “12-month average price”), discounted at 10%, plus the lower of cost or fair market value of unproved properties. If the ceiling is not greater than or equal to the total capitalized costs, then we are required to write down capitalized costs to the ceiling. We perform this ceiling test calculation each quarter. Any required write downs are included in the condensed consolidated statements of operations as an impairment charge.

We recognized $304,903,000 of impairment expense in the first nine months of 2015 compared to $0 in the first nine months of 2014. The impairment expense is primarily due to the reduction in the price of crude oil beginning in the fourth quarter of 2014.

If commodity prices remain at decreased levels, the 12-month average price used in the ceiling calculation will decline and will likely cause additional write downs of our oil and natural gas properties. Continued write downs of oil and natural gas properties may occur until such time as commodity prices have recovered, and remained at recovered levels, so as to meaningfully increase the 12-month average price used in the ceiling calculation. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

Standby Rig Expense

Standby rig expenses totaled $6,173,111 for the first nine months of 2015. We are required to pay for idle time when our remaining rig is unutilized. The remaining drilling rig contract expires on October 31, 2015. We incurred no standby rig expense prior to 2015. Fees related to unutilized frac water commitments are included in standby rig expense, totaling $1,764,545 for the first nine months of 2015. We incurred no fees related to unutilized frac water commitments prior to 2015.

Other Expense, Net

Other expense, net was $5,032,362 for the first nine months of 2015 compared to $4,609,075 for the first nine months of 2014. We recognized a gain of $2,012,000 on the warrant liability for the first nine months of 2015 compared to an expense of $1,751,000 for the first nine months of 2014. 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 $7,044,901 for the first nine months of 2015, compared to $2,515,034 for the first nine months of 2014. The increase in interest expense primarily relates to the balance outstanding on the Credit Facility and increased amortization of debt issuance costs.

30

Net Loss

We had net loss of $330,044,369 for the first nine months of 2015 compared to net income of $10,057,937 for the first nine months of 2014 (representing $(52.10) and $3.03 per share-basic, respectively). The resulting net loss, compared to net income in our period-over-period results, was driven by the impairment expense on our oil and natural gas properties, increased production expenses and lower revenues resulting from lower commodity prices.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Net income (loss)	$	(159,252,623	)	$	13,659,075		$	(330,044,369	)	$	10,057,937
Impairment of oil and natural gas properties		158,278,000			—			304,903,000			—
Interest expense		2,735,348			1,206,571			7,044,901			2,515,034
Accretion of discount on asset retirement obligations		52,500			28,037			153,007			63,837
Depletion, depreciation and amortization		11,474,674			9,298,031			32,181,525			24,323,398
Stock-based compensation		423,145			2,818,161			2,586,898			9,497,044
Warrant revaluation (gain) expense		(221,000	)		(216,000	)		(2,012,000	)		1,751,000
Net gains on commodity derivatives		(12,699,147	)		(11,184,716	)		(8,148,386	)		(3,722,780	)
Net cash settlements received (paid) on commodity derivatives		1,354,804			(313,451	)		5,481,384			(2,775,591	)
Standby rig expense		3,800,446			—			6,173,111			—
Adjusted EBITDA	$	5,946,147		$	15,295,708		$	18,319,071		$	41,709,879

Liquidity and Capital Resources

Our financial statements have been prepared on a going concern basis, which contemplates continuity of operations, realization of assets and the satisfaction of liabilities in the normal course of business. This section should be read in conjunction with “Note 1 — Basis of Presentation and Significant Accounting Policies”, “Note 3 — Liquidity and Capital Resources” and “Note 8 — Revolving Credit Facility” in the notes to the consolidated financial statements included in Part I, Item 1 of this Quarterly Report and Items 1A “Risk Factors” included in Part II of this Quarterly Report. 

As of September 30, 2015, we had available cash of approximately $5.1 million, availability under our reserve-based revolving credit facility (the “Credit Facility”) with Wells Fargo Bank, N.A., as administrative agent, and the lenders party thereto, of approximately $40.0 million, and had drawn approximately $160.0 million.  On October 6, 2015, our borrowing base under the Credit Facility was decreased from $200 million to $120 million as part of a regularly scheduled semi-annual redetermination by our lenders. The decrease in the borrowing base has resulted in the Credit Facility balance exceeding the revised borrowing base by approximately $19.6 million as of November 6, 2015. Under the terms of the Credit Agreement, we are permitted to repay the deficiency in three monthly installments beginning 30 days after the date of the redetermination. We do not expect to be able to make the monthly installments, which will result in a default under the Credit Agreement. Further, the previously announced term loan facility was not consummated and has had an adverse effect on our operations and liquidity. We and our advisors are negotiating with the bank group regarding a repayment schedule and continue to work with a group of term debt providers for a term debt solution. We believe we will need to complete certain transactions, including management of and/or refinancing of our debt capital structure and potential asset sales, to have sufficient liquidity to satisfy all of our obligations, including eliminating the approximate $19.6 million deficiency under the Credit Facility in the near term and obligations such as oil, natural gas and produced water transportation and processing commitments, fixed drilling commitments and operating leases, in the long term.

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As a result of substantial declines in oil and gas prices during the latter half of 2014 and throughout 2015, our liquidity outlook, including our working capital balance and EBITDA, has been impacted.  As a result, we expect lower operating cash flows than previously experienced and if commodity prices continue to remain low, our liquidity will be further impacted. In addition to the default regarding the deficiency repayments under the Credit Agreement described above, we were not in compliance with the total debt to EBITDA and Senior Secured Debt-to-EBITDA ratios under the Credit Facility as of September 30, 2015. The breach of the covenants under the Credit Facility could cause a default under the Credit Facility if not amended or waived by the lending group, and the lenders would be able to accelerate the maturity of the Credit Facility and exercise other rights and remedies. This, in turn, would cause a default under the Convertible Notes due in 2019 and permit the holders of those notes to accelerate their maturity. In accordance with the provisions under ASC 470-10-45-1, we have classified the balances of the Credit Facility and Convertible Notes as current liabilities as of September 30, 2015. Furthermore, the ability to refinance any of the existing indebtedness on commercially reasonable terms may be materially and adversely impacted by the current conditions in the energy industry and our financial condition.

On November 5, 2015, we and certain of our subsidiaries entered into a forbearance agreement (the “Forbearance Agreement”) with the lenders party to the Credit Agreement. Pursuant to the Forbearance Agreement, the Lenders and the Agent agreed to forbear from exercising their rights and remedies under the Credit Agreement until December 18, 2015 (the “Forbearance Period”) with respect to certain events of defaults under the Credit Agreement. For additional information regarding the Forbearance Agreement, see Note 15 Subsequent Events— Forbearance Agreement in the notes to the consolidated financial statements included in Part I, Item 1 of this Quarterly Report.

The commodity price decline has materially reduced the revenues that were generated from the sale of our oil and gas production volumes during that period, which, in turn, has negatively affected our working capital balance and EBITDA. The potential for future oil prices to remain at their current price levels for an extended period of time raises substantial doubt regarding our ability to continue as a going concern. For purposes of this discussion, the term “substantial doubt” refers to concerns that a company may not be able to meet its obligations when they come due. The accompanying financial statements do not include any adjustments related to the recoverability and classification of recorded assets or the amounts and classification of liabilities, other than classifying the outstanding balances of the Credit Facility and Convertible Notes as current liabilities, that might result from the uncertainty associated with the ability to meet obligations as they come due.

We continue to pursue a number of actions including (i) actively managing the debt capital structure, (ii) selling additional assets, (iii) minimizing capital expenditures, (iv) obtaining waivers or amendments from lenders, (v) effectively managing working capital and (vi) improving cash flows from operations. As previously noted, we have engaged financial advisors and other professionals to assist it with reviewing all options to improve its liquidity profile and strengthen our balance sheet. These efforts continue in earnest and we are considering all available strategic alternatives and financing possibilities, including, without limitation, the incurrence of additional secured indebtedness and the exchange or refinancing of existing obligations. We can provide no assurance that these discussions will result in the completion of a transaction, or that any completed transaction will result in sufficient liquidity to satisfy our obligations.

The following table summarizes total current assets, total current liabilities and working capital at September 30, 2015:

Current assets	$	25,320,392
Current liabilities		357,635,408
Working capital	$	(332,315,016	)

Equity Offerings

On February 11, 2015, we completed a public offering of 1,357,956 shares of common stock at a price of $22.40 per share for total net proceeds of approximately $29.4 million.

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At-the-Market Continuous Offering Program

On April 2, 2015, we entered into an equity distribution with two separate financial institutions pursuant to which we may offer and sell, through sales agents, common stock representing an aggregate offering price of up to $100 million through an at-the-market continuous offering program. During September 2015, we issued shares of common stock through our at-the-market continuous offering program totaling 848,961 at an average price of $2.79 per share for total net proceeds of approximately $2.3 million. These sales were made pursuant to the terms of the equity distribution agreements dated April 2, 2015 between us and our sales agents. As of September 30, 2015, we had issued 3,309,006 shares of common stock pursuant to the continuous offering program at an average price of $5.65 per share for total net proceeds of approximately $18.7 million.

Credit Facility

On November 20, 2012, we entered into a senior secured revolving credit facility (as amended, the “Credit Facility”) with Wells Fargo Bank, N.A., as administrative agent (“Wells Fargo”), and the lenders party thereto. The Credit Facility is a senior secured reserve-based revolving credit facility with a maximum commitment of $400 million. On April 30, 2015, in connection with the semi-annual borrowing base redetermination, we and our lending group entered into an amendment to the Credit Facility. The amendment to the Credit Facility reduced the borrowing base from $250 million to $200 million. As of September 30, 2015, we had drawn approximately $160 million toward our $200 million borrowing base under the Credit Facility. Our borrowing base under the Credit Facility was subject to its semi-annual redetermination on October 6, 2015, and the lenders decreased the borrowing base to $120 million. This redetermination resulted in an outstanding deficiency under the Credit Facility of approximately $19.6 million. Under the terms of the Credit Agreement, we are permitted to repay the deficiency in three monthly installments beginning 30 days after the date of the redetermination. We do not expect to be able to make the monthly installments, which will result in a default under the Credit Agreement. 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 5.0 to 1.0 for periods ending on March 31, 2015 through June 30, 2016 and 5.5 to 1.0 for periods ending September 30, 2016 through December 31, 2016 and (c) a Senior Secured Debt-to-EBITDA ratio for periods ending March 31, 2015 through December 31, 2016 of no more than 2.5 to 1.0. We were not in compliance with the total debt to EBITDA and Senior Secured Debt-to-EBITDA ratios under the Credit Facility as of September 30, 2015 and do not expect to be in compliance with these ratios in the near future.

On November 5, 2015, we and certain of our subsidiaries entered into a Forbearance Agreement with the lenders party to the Credit Agreement. Pursuant to the Forbearance Agreement, the Lenders and the Agent agreed to forbear from exercising their rights and remedies under the Credit Agreement until December 18, 2015 with respect to certain events of default under the Credit Agreement. Please see Note 3 – Liquidity and Capital Resources and Note 15 – Subsequent Events – Forbearance Agreement in the notes to the consolidated financial statements included in Part I. Item 1 of this Quarterly Report for further information regarding changes to financing arrangements and changes to the Credit Facility subsequent to September 30, 2015.

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 under the Credit Facility, 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 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 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 September 30, 2015, the annual interest rate on the Credit Facility was 2.70%.

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 September 30, 2015, we have not obtained any letters of credit under the Credit Facility.

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

The Credit Facility allows us to hedge up to 60% of our 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. As of September 30, 2015, we had hedges covering 70% of our projected production through 2016.

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Satisfaction of Our Cash Obligations for the Next Twelve Months

The substantial reduction in oil and natural gas prices has caused a reduction in our forecast of available liquidity and we may not have the ability to generate sufficient liquidity to meet our anticipated working capital, debt service and other liquidity needs for the next twelve months. On October 6, 2015, our borrowing base under our Credit Facility was decreased from $200 million to $120 million as part of our regularly scheduled semi-annual redetermination by our lender. The decrease in the borrowing base has resulted in the outstanding revolving credit facility balance exceeding the revised borrowing base by approximately $19.6 million as of November 6, 2015. We believe that our forecasted cash and available credit capacity are not expected to be sufficient to meet our commitments as they come due over the next twelve months unless we are able to successfully increase our liquidity. A sustained material decline in oil and natural gas prices or a reduction in our oil and natural gas production and reserves would reduce our ability to fund our capital expenditure program and negatively impact our liquidity on an ongoing basis. We expect we will need to complete certain transactions, including management of our debt capital structure and potential asset sales, to have sufficient liquidity to satisfy these obligations in the long-term.

In December 2014, management decided to reduce the 2015 development program given the current commodity price environment. We released two of our three operated rigs in December 2014 and the contract on our third drilling rig expired in October 2015. We have not yet fully developed our budget for 2016 due to economic uncertainty and depressed commodity prices; however, we expect that we may further scale back our development plan should commodity prices remain depressed or decline further. We are currently evaluating strategic alternatives to address our liquidity issues and high debt levels. We cannot assure you that any of these efforts will be successful or will result in cost reductions or additional cash flows or the timing of any such cost reductions or additional cash flows. We have engaged certain financial advisers and other professionals to assist with reviewing our capital structure options. These efforts continue in earnest and we are considering all available strategic alternatives and financing possibilities. We cannot assure you that any refinancing or restructuring would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all. Furthermore, we cannot assure you that any of our strategies will yield sufficient funds to meet our working capital or other liquidity needs, including for payments of interest and principal on our debt in the future, and any such alternative measures may be unsuccessful or may not permit us to meet scheduled debt service obligations, which could cause us to default on our obligations.

Our prospects must be considered in light of the risks, particularly companies in the oil and natural gas exploration industry. 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 under our Credit Facility, impairment assessments of oil and natural gas properties, and values of properties in purchase and sale transactions. Material changes in prices can impact our stock price and therefore our ability to raise capital, borrow money and attract 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 necessary for our operations. See Part II—Other Information—Item IA. Risk Factors.

Derivative Instruments

We have historically used commodity derivative instruments in connection with anticipated oil sales to minimize the impact of product price fluctuations and ensure cash flow for future capital needs. Such instruments include variable to fixed price commodity swaps, collars and put options. See Note 2 Basis of Presentation and Significant Accounting Policies in the notes to the consolidated financial statements included in Part I, Item 1 of this Quarterly Report for our methodology for valuing commodity derivative instruments.

Cash and Cash Equivalents

Our total cash resources as of September 30, 2015 were $5,068,360, compared to $12,389,230 as of December 31, 2014. The decrease in our cash balance was primarily attributable to a decrease in cash flow from operations due to low commodity prices and the suspension of the development of our oil and natural gas properties.

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Net Cash Provided By Operating Activities

Net cash provided by operating activities was $33,677,105 for the first nine months of 2015 compared to $30,969,057 for the first nine months of 2014. The change in the net cash provided by operating activities is primarily attributable to higher production volume, offset by decreased commodity prices, higher production expenses and other operating expenses.

Net Cash Used For Investment Activities

Net cash used in investment activities was $172,915,105 for the first nine months of 2015 compared to $348,524,792 for the first nine months of 2014. The change in net cash used in investment activities for the first nine months of 2015 is primarily attributable to decreased purchases and development of oil and natural gas properties in the Williston Basin as a result of decreased commodity prices.

Net Cash Provided By Financing Activities

Net cash provided by financing activities was $131,917,090 for the first nine months of 2015 compared to $185,861,485 for the first nine months of 2014. The change in net cash provided by financing activities for the first nine months of 2015 is primarily attributable to a reduction in our historical level of equity and debt financing and borrowings net of repayments under our Credit Facility in 2015.

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, 2014, as well as in the Management’s Discussion and Analysis of Financial Condition and Results of Operations section in such Form 10-K. There have been no significant changes in the application of our critical accounting policies during the nine-month period ended September 30, 2015.

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, 2014, in our Quarterly Reports on Form 10-Q for the three months ended March 31, 2015 and June 30, 2015 and the other disclosures contained herein and therein, which describe factors that could cause our actual results to differ from those anticipated in the forward-looking statements, including, but not limited to, the following factors:

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

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

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

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

· our ability to repay or refinance our existing debt as it becomes due;

· our ability to retain key members of management; 

· volatility in commodity prices for oil and natural gas;

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

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

· our ability to obtain permits and government approvals;

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

· the amount of our indebtedness and ability to maintain compliance with 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;

· effects of governmental regulation;

· effect of seasonal weather conditions and wildlife restrictions on our operations;

· effect of local and regional factors on oil and natural gas prices;

· our inability to control operations on properties we do not operate;

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

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

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

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

The price we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile, and these markets will likely continue to be volatile in the future. The prices we receive for our production depend on numerous factors beyond our control. Our revenues during the three and nine months ended September 30, 2015 and 2014 generally have increased or decreased along with any increases or decreases in oil or natural gas prices, but the exact impact on our income is indeterminable given the variety of expenses associated with producing and selling oil and natural gas that also increase and decrease along with oil and natural gas prices.

We recognized ceiling test impairment expense of $158.3 million for the three months ended September 30, 2015. Holding all other reserve factors constant and only adjusting the 12-month average price to an estimated fourth quarter ending average (holding October 2015 prices constant for the remaining two months), we currently anticipate that we could recognize impairment in the fourth quarter of 2015 of approximately $60 million. The estimated fourth quarter 2015 impairment is the result of a decrease in revenues generated from our proved developed producing reserves.

Our Credit Facility allows us to enter into commodity derivative instruments, the notional volumes for which when aggregated with other commodity swap agreements and additional fixed-price physical off-take contracts then in effect, as of the date such instrument is executed, is not greater than 80% of the reasonably anticipated projected production from our proved developed producing reserves. We use swaps to fix the sales price for our anticipated future oil production. Upon settlement, we receive a fixed price for the underlying commodity and pay our counterparty a floating market price, as defined in each instrument. These instruments are settled monthly. When the floating price exceeds the fixed price for a contract month, we pay our counterparty. When the fixed price exceeds the floating price, our counterparty is required to make a payment to us. Currently, we utilize swaps to reduce the effect of price changes on a portion of our future oil production. We do not enter into derivative instruments for trading purposes. All commodity derivative instruments are accounted for using mark-to-market accounting. We settled certain swap contracts early during the year, resulting in approximately $5,317,300 in cash settlements during 2015. We entered into certain put option contracts for oil volumes produced in May 2015 through December 2016, whereby premiums are paid monthly throughout the life of the contracts. Further details on the contracts are provided in the table below.

Settlement Period	Daily Volume Oil (Bbls)		Put Option Fixed Price Per Bbl		Total Volume (Bbls)		Premium Paid Per Bbl		Total Premiums Due
May 2015 – December 2015		4,000	$	55.00		980,000	$	4.88	$	4,782,400
January 2016 – December 2016		3,000	$	60.00		1,098,000	$	7.54	$	8,278,920

We use these commodity derivative instruments as a means of managing our exposure to price changes. While we structure these derivatives to reduce our exposure to changes in price associated with the derivative commodity, they also may limit the benefit we might otherwise have received from market price increases. 

Based on the September 30, 2015 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 asset by approximately $1.5 million.

Interest Rate Risk

At September 30, 2015, we had $151.5 million outstanding under our Convertible Notes due April 1, 2019 at a fixed interest rate of 2.0%. Although near-term changes in interest rates may affect the fair value of our fixed-rate debt, they do not expose us to the risk of earnings or cash flow loss. In addition, as of September 30, 2015, we had $200 million of total borrowings available to us under our Credit Facility, of which approximately $160 million was drawn at September 30, 2015. The Credit Facility bears interest at variable rates. Assuming we had the maximum amount outstanding at September 30, 2015 under our Credit Facility of $200 million, a 1.0% increase in interest rates would result in additional annualized interest expense of $2.0 million. We currently have no interest rate derivative instruments outstanding. However, we may enter into interest rate derivative instruments in the future if we determine that it is necessary to invest in such instruments in order to mitigate our interest rate risk.

For a detailed discussion of the foregoing credit arrangements, including a discussion of the applicable interest rates, please refer to Note 8 – Revolving Credit Facility and Note 9 – Convertible Notes in the notes to the consolidated financial statements included in Part I, Item 1 of this Quarterly Report.

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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. Management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable, not absolute, assurance of achieving their objectives and management necessarily applies its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures as of September 30, 2015. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective to accomplish their objectives as of such date.

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

From time to time, we are party to various legal proceedings arising in the ordinary course of business. Although we cannot predict the outcomes of any such legal proceedings, our management believes that the resolution of currently pending legal actions will not have a material adverse effect on our business, results of operations and financial condition. See Note 14 – Commitments and Contingencies in the notes to the consolidated financial statements included in Part I. Item 1 of this Quarterly Report, which is incorporated in this item by reference.

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, 2014, as filed with the SEC on March 10, 2015 and Item 1A. – “Risk Factors” of our Quarterly Reports on Form 10-Q for the three months ended March 31, 2015, as filed with the SEC on May 4, 2015, and for the three months ended June 30, 2015, as filed with the SEC on August 4, 2015, that could have a material adverse effect on our business, results of operations, financial condition and/or liquidity and that could cause our operating results to vary significantly from period to period. As of September 30, 2015, there have been no material changes to the risk factors disclosed in our most recent Annual Report on Form 10-K and our Quarterly Reports on Form 10-Q, except as stated below. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition, or operating results in the future.

If we are unable to repay or refinance our existing and future debt as it becomes due, we may be unable to continue as a going concern.

Our existing and future debt agreements could create issues as interest payments become due and the debt matures that will threaten our ability to continue as a going concern. If we fail to satisfy our obligations with respect to our indebtedness or fail to comply with the financial and other restrictive covenants contained in the Credit Facility, the Indenture governing our Convertible Notes, or other agreements governing our indebtedness, an event of default could result, which would permit acceleration of such debt and which could result in an event of default under and acceleration of our other debt and could permit our secured lenders to foreclose on any of our assets securing such debt. Any accelerated debt would become immediately due and payable. While we will attempt to take appropriate mitigating actions to refinance any indebtedness prior to its maturity or otherwise extend the maturity dates, and to cure any potential defaults, there is no assurance that any particular actions with respect to refinancing existing indebtedness, extending the maturity of existing indebtedness or curing potential defaults in our existing and future debt agreements will be sufficient.

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There is doubt about our ability to maintain adequate liquidity through December 31, 2016.

The substantial reduction in oil and natural gas prices has caused a reduction in our forecast of available liquidity and we may not have the ability to generate sufficient liquidity to meet our anticipated working capital, debt service and other liquidity needs. On October 6, 2015, our borrowing base under our Credit Facility was decreased from $200 million to $120 million as part of our regularly scheduled semi-annual redetermination by our lender. The decrease in the borrowing base has resulted in the outstanding revolving credit facility balance exceeding the revised borrowing base by approximately $19.6 million as of November 6, 2015. Further, the previously announced term loan facility was not consummated. We believe that our forecasted cash and available credit capacity are not expected to be sufficient to meet our commitments as they come due over the next twelve months unless we are able to successfully increase our liquidity. A sustained material decline in oil, natural gas and NGL prices or a reduction in our oil and natural gas production and reserves would reduce our ability to fund our capital expenditure program and negatively impact our liquidity on an ongoing basis. We expect we will need to complete certain transactions, including management of our debt capital structure and potential asset sales, to have sufficient liquidity to satisfy these obligations in the long-term.

We are currently evaluating strategic alternatives to address our liquidity issues and high debt levels. We cannot assure you that any of these efforts will be successful or will result in cost reductions or additional cash flows or the timing of any such cost reductions or additional cash flows. We have engaged certain financial advisers and other professionals to assist with reviewing our capital structure options. These efforts continue in earnest and we are considering all available strategic alternatives and financing possibilities. We cannot assure you that any refinancing or restructuring would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all. Furthermore, we cannot assure you that any of our strategies will yield sufficient funds to meet our working capital or other liquidity needs, including for payments of interest and principal on our debt in the future, and any such alternative measures may be unsuccessful or may not permit us to meet scheduled debt service obligations, which could cause us to default on our obligations.

We may not have the ability to raise the funds necessary to purchase our Convertible Notes upon a Fundamental Change.

Holders of our Convertible Notes will have the right to require us to purchase the Convertible Notes upon the occurrence of a Fundamental Change (as defined in the Indenture at 100% of their principal amount plus accrued and unpaid interest.  However, we may not have enough available cash or be able to obtain financing at the time we are required to make purchases of tendered Convertible Notes.  In addition, our ability to purchase the Convertible Notes may be limited by law, by regulatory authority or by the agreements governing our then current and future indebtedness.  Our failure to purchase tendered Convertible Notes at a time when the purchase is required by the terms of the Indenture governing the Convertible Notes would constitute a default under the Indenture. A default under the Indenture or a Fundamental Change itself could also lead to a default or require a prepayment under, or result in the acceleration of the maturity or purchase of, our existing or future other indebtedness.  The requirement that we offer to purchase the Convertible Notes upon a Fundamental Change is limited to the transactions specified in the definition of a Fundamental Change, which definition may differ from the definition of a fundamental change or change of control in the agreements governing our existing or future other indebtedness.  If the repayment of the related indebtedness were to be accelerated after any applicable notice or grace periods, we may not have sufficient funds to repay the indebtedness and purchase the Convertible Notes.

We have been and may in the future be subject to a redetermination of the borrowing base under our Credit Facility and we may be unable to obtain additional capital that we will require to implement our business plan, which could restrict our ability to grow. Further, we are required to comply with certain financial covenants under our Credit Facility on a quarterly basis, and as of September 30, 2015 we were not in compliance with certain of these covenants, which would have an adverse effect on our operations and liquidity if our Credit Facility is not amended or waived.

Our Credit Facility limits our borrowings to the lesser of the borrowing base and the total commitments. In connection with a redetermination in April 2015, our borrowing base was reduced from $250.0 million to $200.0 million. In October 2015, our borrowing base was further reduced to $120.0 million, resulting in a deficiency under our borrowing base of approximately $19.6 million in connection with a subsequent redetermination. Our borrowing base is determined semi-annually, and may also be redetermined at the election of us or the banks between the scheduled redeterminations. Lower oil and natural gas prices may result in further reductions to our borrowing base at subsequent redeterminations.

We would anticipate prolonged depression of pricing may equate to further decreases in our borrowing base, which may or may not be offset by increases in production. Further, as a general rule, we experience a significant lag time between the initial cash outlay on the development of a prospect and the inclusion of any value for such prospect in the borrowing base. Until a well is on production, the banks may assign only a minimal borrowing base value to the well, and cash flows from the well are not available to fund our operating expense. Delays in bringing wells on production may reduce the borrowing base significantly, depending on the amounts borrowed and the length of the delays.

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The reduction in our borrowing base in October 2015 requires us to repay the $19.6 million in excess of the borrowing base. Under the terms of the Credit Agreement, we are obligated to repay the deficiency in three monthly installments following the date of the redetermination. We do not expect to be able to make the monthly installments, which will result in a default under the Credit Agreement. We and our advisors are negotiating with the lending group regarding a repayment schedule and continue to work with a group of term debt providers for a term debt solution. We believe we will need to complete certain transactions, including management of and/or refinancing of our debt capital structure and potential asset sales, to have sufficient liquidity to satisfy all of our obligations, including eliminating the approximate $19.6 million deficiency under the Credit Facility in the near term and obligations such as oil, natural gas and produced water transportation and processing commitments, fixed drilling commitments and operating leases, in the long term. As a result, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out our business plans, which would materially and adversely impact our financial condition and results of operations and impair our ability to service our indebtedness. Additionally, our Credit Facility contains covenants limiting our ability to incur additional indebtedness and requiring us to maintain certain financial ratios, 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 5.0 to 1.0 for periods ending on March 31, 2015 through June 30, 2016 and 5.5 to 1.0 for periods ending September 30, 2016 through December 31, 2016 and (c) a Senior Secured Debt-to-EBITDA ratio for periods ending March 31, 2015 through December 31, 2016 of no more than 2.5 to 1.0. We were not in compliance with the total debt to EBITDA and Senior Secured Debt-to-EBITDA ratios under the Credit Facility as of September 30, 2015. A resultant breach of the covenants and the breach of the deficiency repayment under our Credit Facility could cause a default under the Credit Agreement if not amended by the lending group, and the lenders would be able to accelerate the maturity of the credit agreement and exercise other rights and remedies. This, in turn, would cause a default under the Convertible Notes and permit the holders of those notes to accelerate their maturity. Any violation of the terms of the Forbearance that would result in a default of the Credit Agreement and subsequent cross-default under the Convertible Notes would have an adverse effect on our operations and liquidity.

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

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

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

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

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

Our current financial condition and lower commodity prices have adversely affected our business operations and our business prospects.

Our current financial condition and lower commodity prices and the resulting uncertainty have been disruptive to our business. Management has devoted substantial time and attention to improving our financial condition, thereby reducing its focus on operating the business.  We may also lose employees as a result of uncertainties related to our financial condition.  Further, our current financial condition and resulting uncertainty may cause operating partners to terminate their relationships with us or to tighten credit. These developments could have a material adverse effect on our business, operations, financial condition and cash flows.  Moreover, if we are unable to raise a sufficient amount of cash to pay for our portion of costs associated with drilling programs, we would be subject to customary non-consent penalties on an individual well by well basis with respect to any wells in which we are unable to participate, which would result in the loss of a significant portion of any future revenue derived from those non-consent wells.  Similarly, if we are unable to fund renewals of expiring leases, we could lose portions of our acreage.

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We are subject to commitments to transport and process a minimum amount of oil, natural gas and produced water through April 2020, and we are currently not meeting the minimum requirements, which has required us to make deficiency payments and resulted in an additional impairment of our proved reserves. Additional deficiency payments will adversely affect our cash flows from operations and may result in additional impairments of our proved reserves.

We have commitments for the transportation and processing of our production on certain wells within our operating area in the Williston Basin of North Dakota, including an aggregate minimum commitment to deliver on a gross basis 16.4 MMBbls of oil at a fee of $1.21/Bbl, 10.9 Bcf of natural gas at a fee of $1.67/Mcf and 28.2 MMBbls of produced water at a fee of $0.82/Bbl through April 2020. We are required to make monthly deficiency payments for any shortfalls in delivering the minimum volumes under these commitments. Currently, we have insufficient production to meet these contractual commitments. The commitment price can be adjusted in future years. These future transportation and processing commitments may expose us to additional volume deficiency payments. For the three months ended September 30, 2015, we incurred deficiency fees of $1.0 million and expect to continue to accrue deficiency fees under our commitments as long as our development program is suspended. The deficiency fees are included as production expenses in the statement of operations for the three and nine months ended September 30, 2015. Transportation costs aside from the deficiency fee are included in the realized price of oil and natural gas revenues in the statement of operations for the three and nine months ended September 30, 2015. Estimated future deficiency fees are included in the calculation of the present value of estimated future net revenues from proved oil and natural gas reserves, which impacts the ceiling test impairment calculation. Additional deficiency fees in the future may have a material adverse effect on us, our operations and result in further impairments of our proved reserves.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

Defaults under Credit Facility

On November 20, 2012, we entered into a senior secured revolving credit facility (as amended, the “Credit Facility”) with Wells Fargo Bank, N.A., as administrative agent (“Wells Fargo”), and the lenders party thereto. The Credit Facility is a senior secured reserve-based revolving credit facility with a maximum commitment of $400 million. On April 30, 2015, in connection with the semi-annual borrowing base redetermination, we and our lending group entered into an amendment to the Credit Facility, which reduced the borrowing base from $250 million to $200 million. As of September 30, 2015, we had drawn approximately $160 million toward the $200 million borrowing base under the Credit Facility. The borrowing base under the Credit Facility was subject to a semi-annual redetermination on October 6, 2015, and the lenders decreased the borrowing base to $120 million. This redetermination resulted in an outstanding deficiency under the Credit Facility of approximately $19.6 million. Under the terms of the Credit Facility, we are permitted to repay the deficiency in three monthly installments beginning 30 days after the date of the redetermination. We do not expect to be able to make the monthly installments, which will result in a default under the Credit Facility. The Credit Facility also 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 5.0 to 1.0 for periods ending on March 31, 2015 through June 30, 2016 and 5.5 to 1.0 for periods ending September 30, 2016 through December 31, 2016 and (c) a Senior Secured Debt-to-EBITDA ratio for periods ending March 31, 2015 through December 31, 2016 of no more than 2.5 to 1.0. We were not in compliance with the total debt to EBITDA and Senior Secured Debt-to-EBITDA ratios under the Credit Facility as of September 30, 2015 and do not expect to be in compliance in the near term.

An event of default under the Credit Facility permits Wells Fargo and the other lenders to accelerate repayment of all amounts due and to terminate the commitments thereunder. Any default of the payments of monies when due under the Credit Facility would also result in a default under the Convertible Notes. We do not have sufficient cash resources to repay these amounts if the lenders accelerate the obligations under the Credit Facility.

On November 5, 2015, we and our subsidiaries entered into a Forbearance Agreement with the lenders party to the Credit Facility. Pursuant to the Forbearance Agreement, the lenders and the agent agreed to forbear from exercising their rights and remedies under the Credit Facility until December 18, 2015 with respect to certain events of defaults under the Credit Facility. Please see Note 3 – Liquidity and Capital Resources and Note 15 – Subsequent Events – Forbearance Agreement for further information regarding changes to financing arrangements and changes to the Credit Facility subsequent to September 30, 2015.

The terms of the Credit Facility (including a full description of the rights and remedies of our lenders upon an event of default), and copies of the agreements related to the Credit Facility can be found in our prior filings with the SEC, including the Quarterly Reports on Forms 10-Q filed with the SEC on May 5, 2014 and May 4, 2015, and the Current Report on Form 8-K filed with the SEC on September 4, 2014, which are incorporated herein by reference, in our Form 10-K filed with the SEC on March 10, 2015 and Forms 10-Q filed on May 4, 2015 and August 5, 2015. A copy of the Forbearance Agreement is filed as Exhibit 10.3 to this Quarterly Report on Form 10-Q and is hereby incorporated herein by reference.

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ITEM 5. OTHER INFORMATION

Entry into New Employment Agreements

On October 29, 2015, our Compensation Committee provided McAndrew Rudisill, our Chief Executive Officer, with a notice of non-extension of Mr. Rudisill’s current employment agreement for another one-year term. As a result of the non-extension of the term of employment of the current employment agreement, the current employment agreement will terminate on December 31, 2015. On November 5, 2015, our Compensation Committee approved employment agreements (the “Employment Agreements”) with the following named executive officers of the Company (collectively, the “Officers”):

McAndrew Rudisill	President and Chief Executive Officer
Michael Dickinson	Chief Operating Officer
Ryan Smith	Chief Financial Officer

The terms of the Employment Agreements will become effective on January 1, 2016. The Employment Agreements are for an initial term ending December 31, 2016 and automatically extend for an additional one year period every year thereafter unless either party gives written notice at least 60 days prior to the end of the term that the automatic extension will not occur.

Under the terms of the Employment Agreements, each Officer will receive an annual base salary in the amount set forth below, subject to any increase the Compensation Committee may deem appropriate from time to time.

McAndrew Rudisill	$	450,000
Michael Dickinson	$	375,000
Ryan Smith	$	325,000

In addition, the Officers will be eligible to receive annual cash bonuses and annual equity bonus grants, beginning with the Company’s 2016 fiscal year. The amount of the cash bonus payment and equity bonus grants made to the Officers will be linked to our performance according to certain predetermined performance criteria and any other conditions as determined by the Compensation Committee in its sole discretion. A minimum threshold level of performance must be achieved or no cash or equity bonus will be paid with respect to such performance period.

If we terminate an Officer due to the Officer’s death, disability, by us without “cause” or by the Officer for “good reason” (as such terms are defined in the Employment Agreement), the Employment Agreements provide for payment to the Officer of (i) any unpaid portion of the Officer’s base salary and benefits accrued through the date of termination, (ii) any unpaid annual bonus, if any, relating to a previously completed fiscal year, (iii) the pro-rated annual bonus, if any, for the current fiscal year, (iv) a lump sum cash payment equal to 18 times the applicable percentage of monthly Consolidated Omnibus Reconciliation Act, or COBRA, premiums applicable to the Officer, (v) any unpaid or unreimbursed business expenses, (vi) any benefits under provided under Company employee benefit plans upon a termination in accordance with the plan terms, and (vii) the full amount of remaining and unpaid base salary that would have been paid had the Officer served the duration of the term of employment. In addition, all equity awards previously granted to such Officer will vest immediately.

If we terminate an Officer’s Employment Agreement for “cause” (as such term is defined in the Employment Agreement), then the Officer will not be entitled to a severance payment or any other termination benefits, however the Officer will receive (i) any unpaid portion of the Officer’s base salary, (ii) any unpaid or unreimbursed business expenses, (iii) any benefits provided under Company employee benefit plans upon a termination in accordance with the plan terms, and (iv) a lump sum cash payment equal to 12 times the monthly COBRA premium. Any unvested equity awards previously granted to such Officer will be forfeited.

If an Officer terminates his Employment Agreement without “good reason” (as such term is defined in the Employment Agreement), then the Company will pay the Officer (i) any unpaid portion of the Officer’s base salary, (ii) any unpaid or unreimbursed business expenses, (iii) any benefits provided under Company employee benefit plans upon a termination in accordance with the plan terms, and (iv) any unpaid annual bonus in respect of any completed fiscal year.

If upon a “change in control” (as such term is defined in the Employment Agreement) or eighteen months thereafter, an Officer is terminated without cause, or the Officer terminates with good reason, then the Officer is entitled to (i) any unpaid portion of the Officer’s base salary, (ii) any unpaid or unreimbursed business expenses, (iii) any benefits provided under Company employee benefit plans upon a termination in accordance with the plan terms, (iv) any unpaid annual bonus in respect of any completed fiscal year, (v) one times the Officer’s 2016 base salary and (vi) a lump sum cash payment equal to 12 times the monthly COBRA premium.

The foregoing descriptions are not complete and are qualified in their entirety by reference to the full text of the Employment Agreements, copies of which are attached as Exhibits 10.7, 10.8 and 10.9 to this Quarterly Report on Form 10-Q and are hereby incorporated herein by reference.

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)

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 Certificate of Amendment to the Certificate of Incorporation dated May 20, 2015 (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on May 20, 2015, and incorporated herein by reference)

3.3 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)

3.4 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)

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3.5 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)

10.1 Purchase And Sale Agreement, dated July 31, 2015, by and among Koch Exploration Company, LLC and Emerald Oil, Inc., Emerald WB LLC and Emerald NWB, LLC (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on August 3, 2015, and incorporated herein by reference)

10.2* Exchange Agreement, dated October 22, 2015, by and between Emerald Oil, Inc. and the Holder

10.3* Limited Forbearance Agreement, dated November 5, 2015, by and among Emerald Oil, Inc. and the lenders party thereto

10.4* Amended and Restated Crude Oil Dedication and Throughput Commitment Transportation Agreement, dated May 26, 2015, by and among, Dakota Midstream, LLC, Dakota Energy Connection, LLC, Emerald Oil, Inc. and Emerald WB LLC

10.5* Amended and Restated Gas Dedication and Gathering Agreement, dated May 26, 2015 by and among, Dakota Midstream, LLC, Emerald Oil, Inc. and Emerald WB LLC

10.6* Amended and Restated Water Dedication and Gathering Agreement, dated May 26, 2015 by and among, Dakota Fluid Solutions LLC, f/k/a Mesa Oil Services, LLC, Emerald Oil, Inc. and Emerald WB LLC

10.7* Employment Agreement, dated November 5, 2015, to be effective as of January 1, 2016, by and between Emerald Oil, Inc. and McAndrew Rudisill

10.8* Employment Agreement, dated November 5, 2015, to be effective as of January 1, 2016, by and between Emerald Oil, Inc. and Michael Dickinson

10.9* Employment Agreement, dated November 5, 2015, to be effective as of January 1, 2016, by and between Emerald Oil, Inc. and Ryan Smith

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.

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SIGNATURES

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

Dated: November 6, 2015	EMERALD OIL, INC.
	/s/ McAndrew Rudisill
	McAndrew Rudisill
	Chief Executive Officer (principal executive officer)
	/s/ Ryan Smith
	Ryan Smith
	Chief Financial Officer (principal financial officer)

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EX-10.2

Exhibit 10.2

EXCHANGE AGREEMENT

This Exchange Agreement (this “Agreement”) is made and entered into on October 22, 2015, by and between Emerald Oil, Inc., a Delaware corporation (the “Company”), ZP Master Utility Fund, Ltd. (“ZP Master”) and P Zimmer Ltd. (P Zimmer Ltd., collectively with ZP Master, the “Holder”) of 2.00% Convertible Senior Notes due 2019 (the “Convertible Notes”) issued by the Company.

RECITALS

WHEREAS, the Holder currently holds $16,500,000 principal amount of the Convertible Notes;

WHEREAS, the Holder desires to exchange $3,000,000 of its Convertible Notes, at the rate of $500.00 per $1,000.00 of principal amount to be exchanged (the “Exchange Notes”), for shares of the Company’s common stock, par value $0.001 per share (“Common Stock”), on the terms and conditions set forth in this Agreement (the “Exchange”);

WHEREAS, the Company desires to issue to the Holder that number of shares of the Company’s Common Stock determined as set forth in Section 1.1(b) below in exchange for the Convertible Notes in the Exchange;

NOW, THEREFORE, in consideration of the premises and the agreements set forth below, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties agree as follows:

ARTICLE I

Exchange

Section 1.1          Exchange and Sale of Convertible Notes for Common Stock.

(a)         Upon the terms and subject to the conditions of this Agreement, on the Closing Date (as defined herein), the Company shall issue, subject to Section 1.1(d) and Section 1.2 hereof, to the Holder, and the Holder agrees to accept from the Company, the number of shares of Common Stock determined in accordance with the terms of subsection (b) hereof in exchange for the Exchange Notes.

(b)         On the Closing Date, the Holder will receive a final number of shares of Common Stock determined as set forth below plus a cash payment representing any unpaid interest on the Exchange Notes being exchanged that has accrued through the Closing Date. The number of shares of Common Stock issued to the Holder in exchange for the Exchange Notes pursuant to the terms of this Agreement is referred to herein as the “Exchange Shares.” The Exchange Shares shall equal the principal amount of Exchange Notes to be exchanged at a conversion price of $500.00 per $1,000 of Exchange Notes, divided by the “Share Price” (as defined below), rounded down to the nearest whole share.

(c)         Definitions. For purposes of this Exchange Agreement:

(i) “Share Price” means the 85% of the arithmetic average of the daily VWAPs over the Averaging Period.

(ii) “VWAP” means for each of the fifteen (15) consecutive Trading Days during the Averaging Period, the per share volume-weighted average price of the Common Stock as displayed under the heading “Bloomberg VWAP” on Bloomberg page “EOX equity AQR” (or its equivalent successor if such page is not available) in respect of the period from the scheduled open of trading until the scheduled close of trading of the primary trading session on such Trading Day (or if such volume-weighted average price is unavailable, the market value of one share of the Common Stock on such Trading Day determined, using a volume weighted average method, by a nationally recognized independent investment banking firm retained for this purpose by the Company and Holder). The volume weighted average price used for purposes of the VWAP will be determined without regard to after hours trading or any other trading outside of the regular trading session hours.

(iii) “Averaging Period” means the fifteen (15) consecutive Trading Day period beginning on October 23, 2015 and ending after the scheduled close of trading on November 12, 2015 (assuming that no Market Disruption Event occurs between October 23, 2015 and November 12, 2015).

(iv) “Trading Day” means a day on which (i) there is no Market Disruption Event (as defined below), and (ii) trading in the Company’s securities generally occurs on the New York Stock Exchange.

(v) “Market Disruption Event” means the occurrence or existence on any Scheduled Trading Day (as defined below) for the Common Stock of any suspension or limitation imposed on trading of the Common Stock (by reason of movements in price exceeding limits permitted by the relevant stock exchange or otherwise) in the Common Stock, and such suspension or limitation occurs or exists throughout the 30 minutes prior to the closing time of the relevant exchange on such day.

(vi) “Scheduled Trading Day” means a day that is regularly scheduled Trading Day of the New York Stock Exchange.

(d)         The Company and the Holder agree that the amount of the Exchange Notes being exchanged pursuant to this Agreement shall automatically be reduced (in multiples of $1,000) so that the Company shall not issue Common Stock in Exchange for the Exchange Notes, to the extent that after giving effect to such Exchange, the Holder (together with the Holder’s affiliates or any other person deemed to be a member of a Section 13(d)(3) group with the Holder with respect to Common Stock of the Company) would beneficially own in excess of 9.9% of the Common Stock outstanding immediately after giving effect to such Exchange. The Holder acknowledges that as a result of this restriction, the number of shares that may be issued upon the Exchange may change depending upon changes in the outstanding shares of Common Stock.  Immediately prior to the settlement of the Exchange, the Holder shall certify the number of shares of Common Stock that it beneficially owns (including through other derivative securities) and the shares of Common Stock beneficially owned by the Holder’s affiliates and any other person with whom it may have formed a Section 13(d)(3) “group.”  Any portion of the Convertible Notes not exchanged due to the above limitations will remain outstanding.

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(e)         Upon execution of the Agreement, the Company will promptly make a public announcement regarding the Exchange. Following such announcement, the Confidentiality Agreement between the Company and Zimmer Partners, L.P., dated October 7, 2015, shall be terminated and of no further effect.

Section 1.2          Cancellation of Convertible Notes.  Pursuant to the Indenture dated as of March 24, 2014 between the Company and U.S. Bank National Association, as Trustee, governing the Convertible Notes (the “Indenture”), the Holder hereby agrees that the aggregate principal amount and all accrued unpaid interest on the Exchange Notes shall be cancelled on the completion of the Exchange. The Holder acknowledges that the cancellation of the Exchange Notes shall have the effects specified in the Indenture.

Section 1.3          Section 3(a)(9) Exchange.  In consideration of and for the Exchange, the Company agrees to issue to the Holder the Exchange Shares. The issuance of the Exchange Shares to the Holder will be made without registration of such Exchange Shares under the Securities Act of 1933, as amended (together with the rules and regulations thereunder, the “Securities Act”), in reliance upon the exemption therefrom provided by Section 3(a)(9) of the Securities Act. The Holder acknowledges that the Company is relying upon the truth and accuracy of, and the Holder’s compliance with, its representations, warranties, agreements, acknowledgments and understandings set forth herein in order to determine the availability of such exemptions and the eligibility of the Holder for the Exchange.

Section 1.4          Closing Mechanics.  The closing of the transactions contemplated by this Agreement shall occur on 9:00 a.m., Mountain Standard Time, on November 13, 2015 or at such other time on the same date or such other date as the parties may agree in writing (such time and date, the “Closing Date”). Prior to the Closing Date, Holder shall instruct its broker or other participant in the Fast Automated Securities Transfer Program of The Depository Trust Company (“DTC”) to transfer and deliver the Exchange Notes to the Trustee for purposes of cancellation. On the Closing Date, the Company will deliver the shares of Common Stock to be issued in the Exchange to the transfer agent of the Company to be transmitted to the Holder by crediting the account of Holder’s prime broker with DTC through DTC’s Deposit/Withdrawal at Custodian (“DWAC”) program.

Section 1.5          Conditions to Closing.

(a)         The obligation of the Holder hereunder to consummate the transactions contemplated hereby at the Closing is subject to the satisfaction, at or before the Closing Date, of each of the following conditions, provided that these conditions are for the Holder’s sole benefit and may be waived by the Holder at any time in its sole discretion by providing the Company with prior written notice thereof:

(i)         The Company shall have caused its transfer agent to credit to Holder or its designee the Exchange Shares;

(ii)        The Company shall have submitted an additional share listing application for the Exchange Shares with the NYSE MKT on or prior to the Closing Date and shall cause the Exchange Shares to be approved by the NYSE MKT for listing on the Closing Date or as soon as practicable thereafter; and

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(iii)       The representations and warranties of the Company in this Agreement shall be true and correct in all material respects on and as of the Closing Date with the same effect as if made on the Closing Date and the Company has complied in all material respects with all the agreements and satisfied all the conditions on its part to be performed or satisfied at or prior to the Closing Date.

(b)         The obligation of the Company hereunder to consummate the transactions contemplated hereby at the Closing is subject to the satisfaction, at or before the Closing Date, of each of the following conditions, provided that these conditions are for the Company’s sole benefit and may be waived by the Company at any time in its sole discretion by providing the Holder with prior written notice thereof:

(i)         The Holder shall have delivered, or caused to be delivered, to the Company (x) the Exchange Notes being exchanged pursuant to this Agreement in accordance with the written instructions of the Company and (y) all documentation related to the right, title and interest in and to all of the Exchange Notes, and whatever documents of conveyance or transfer may be necessary or reasonably desirable to transfer to and confirm in the Company all right, title and interest in and to (free and clear of any mortgage, lien, pledge, charge, security interest, encumbrance, title retention agreement, option, equity or other adverse claim thereto) the Exchange Notes.

(ii)        The representations and warranties of the Holder in this Agreement shall be true and correct in all material respects on and as of the Closing Date with the same effect as if made on the Closing Date and that the Holder shall have complied in all material respects with all the agreements and satisfied all the conditions on its part to be performed or satisfied at or prior to the Closing Date.

ARTICLE II

Representations and Warranties of the Holder

The Holder hereby makes the following representations and warranties, each of which is true and correct on the date hereof and the Closing Date and shall survive the Closing Date and the transactions contemplated hereby to the extent set forth herein:

Section 2.1          Existence and Power.

(a)         The Holder is duly organized, validly existing and in good standing under the laws of the jurisdiction of its organization and has the power, authority and capacity to execute and deliver this Agreement, to perform its obligations hereunder, and to consummate the transactions contemplated hereby.

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(b)         The execution of this Agreement by the Holder and the consummation by the Holder of the transactions contemplated hereby do not and will not constitute or result in a breach, violation, conflict or default under any note, bond, mortgage, deed, indenture, lien, instrument, contract, agreement, lease or license to which the Holder is a party, whether written or oral, express or implied, or any statute, law, ordinance, decree, order, injunction, rule, directive, judgment or regulation of any court, administrative or regulatory body, governmental authority, arbitrator, mediator or similar body on the part of the Holder or on the part of any other party thereto or cause the acceleration or termination of any obligation or right of the Holder, except for such breaches, conflicts, defaults, rights or violations which would not, individually or in the aggregate, reasonably be expected to have a Material Adverse Effect on the ability of the Holder to perform its obligations hereunder. As used in this Agreement, the term “Material Adverse Effect” shall mean a material adverse effect on the business, condition (financial or otherwise), properties or results of operations of the party, or an event, change or occurrence that would materially adversely affect the ability of the party to perform its obligations under this Agreement which would limit the Holder’s power to transfer the Exchange Notes hereunder.

Section 2.2          Valid and Enforceable Agreement; Authorization.  This Agreement has been duly executed and delivered by the Holder and constitutes a legal, valid and binding obligation of the Holder, enforceable against the Holder in accordance with its terms, except that such enforcement may be subject to (a) bankruptcy, insolvency, reorganization, moratorium or other similar laws affecting or relating to enforcement of creditors’ rights generally, and (b) general principles of equity.

Section 2.3          Title to Exchange Notes.  The Holder has good and valid title to the Exchange Notes in the aggregate principal amount set forth in the recitals to this Agreement, free and clear of any mortgage, lien, pledge, charge, security interest, encumbrance, title retention agreement, option, equity or other adverse claim thereto. The Holder has not, in whole or in part, (i) assigned, transferred, hypothecated, pledged or otherwise disposed of the Exchange Notes or its rights in such Exchange Notes, or (ii) given any person or entity any transfer order, power of attorney or other authority of any nature whatsoever with respect to such Exchange Notes which would limit the Holder’s power to transfer the Exchange Notes hereunder.

Section 2.4          Investment Decision.  The Holder is a “qualified institutional buyer” within the meaning of Rule 144A under the Securities Act and was not organized for the purpose of acquiring the Exchange Shares. The Holder is knowledgeable, sophisticated and experienced in business and financial matters and has previously invested in securities similar to the Exchange Shares. The Holder is able to bear the economic risk of its investment in the Exchange Shares and is presently able to afford the complete loss of such investment.

The Holder (or its authorized representative) has had the opportunity to review the Company’s filings with the Securities and Exchange Commission (the “Commission”), including, without limitation, the Company’s Annual Report on Form 10-K for the year ended December 31, 2014; the Company’s Quarterly Reports on Form 10-Q for the quarters ended March 31, 2015 and June 30, 2015; the Company’s current reports on Form 8-K filed on January 30, 2015, February 2, 2015, February 11, 2015, March 10, 2015, April 2, 2015, May 4, 2015, May 11, 2015, May 18, 2015, May 20, 2015, May 21, 2015, May 29, 2015, June 11, 2015, August 3, 2015, August 5, 2015, October 2, 2015 and October 13, 2015; and the Company’s Proxy Statement filed on April 24, 2015 (all of such filings with the Commission referred to, collectively, as the “SEC Documents”). The Holder has had such opportunity to ask questions of the Company and its representative and to obtain from representatives of the Company such information as is necessary to permit it to evaluate the merits and risks of its investment in the Company. The Holder has independently, without reliance upon any representatives of the Company and based on such information as the Holder deemed appropriate, made its own analysis and decision to enter into this Agreement. The Holder has had the opportunity to consult with its accounting, tax, financial and legal advisors to be able to evaluate the risks involved in the Exchange pursuant hereto and to make an informed investment decision with respect to such exchange.

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The Holder acknowledges that the Company is relying on the truth and accuracy of the foregoing representations and warranties in the offering of the Exchange Shares to the Holder without having first registered the Exchange Shares under the Securities Act.

Section 2.5          Affiliate Status.  The Holder is not, and has not been during the preceding three months, an “affiliate” of the Company as such term is defined in Rule 144 under the Securities Act.

Section 2.6          Professional Advice.  With respect to the tax, accounting and other economic considerations involved in the Exchange, the Holder is not relying on the Company or any of its affiliates, and the Holder has carefully considered and has, to the extent the Holder believes such discussion is necessary, discussed with the Holder’s professional legal, tax, accounting and financial advisors the implications of the Exchange for the Holder’s particular tax, accounting and financial situation.

Section 2.7          No Solicitation.  The Holder was not solicited by anyone on behalf of the Company to enter into this transaction.

ARTICLE III

Representations, Warranties and Covenants of the Company

The Company hereby makes the following representations, warranties, and covenants each of which is true and correct on the date hereof and shall survive the date of the Closing and the transactions contemplated hereby to the extent set forth herein.

Section 3.1          Existence and Power.

(a)         The Company is duly incorporated, validly existing and in good standing under the laws of Delaware, with the requisite power and authority to own and use its properties and assets and to carry on its business as currently conducted. The Company has the requisite power and authority to execute and deliver this Agreement, to perform its obligations hereunder and consummate the transactions contemplated hereby.

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(b)         The execution of this Agreement by the Company and the consummation by the Company of the transactions contemplated hereby (i) does not require the consent, approval, authorization, order, registration or qualification of, or filing with, any governmental authority or court, or body or arbitrator having jurisdiction over the Company, other than the NYSE MKT and DTC; and (ii) does not and will not constitute or result in a breach, violation or default under any note, bond, mortgage, deed, indenture, lien, instrument, contract, agreement, lease or license, whether written or oral, express or implied, or with the certificate of incorporation or bylaws of the Company, or any statute, law, ordinance, decree, order, injunction, rule, directive, judgment or regulation of any court, administrative or regulatory body, governmental authority, arbitrator, mediator or similar body on the part of the Company or on the part of any other party thereto or cause the acceleration or termination of any obligation or right of the Company or any other party thereto, except for such breaches, violations or defaults which would not reasonably be expected to, singly or in the aggregate, result in a Material Adverse Effect (as defined above) on the ability of the Company to perform its obligations hereunder.

Section 3.2          Valid and Enforceable Agreement; Authorization.  This Agreement has been duly executed and delivered by the Company and constitutes a legal, valid and binding obligation of the Company, enforceable against the Company in accordance with its terms, except that such enforcement may be subject to (a) bankruptcy, insolvency, reorganization, moratorium or other similar laws affecting or relating to enforcement of creditors’ rights generally, and (b) general principles of equity.

Section 3.3          Valid Issuance of the Exchange Shares.  The Exchange Shares, when issued and delivered in accordance with the terms and for the consideration set forth in this Agreement, will be validly issued, fully paid and non-assessable and free of restrictions on transfer other than restrictions on transfer under applicable federal and state securities laws and liens or encumbrances created by or imposed by the Holder. Assuming the accuracy of the representations of the Holder in Article II of this Agreement, the Exchange Shares will be issued in compliance in all material respects with all applicable federal and state securities laws. The Company has a sufficient number of authorized and unissued shares of Common Stock to consummate the Exchange.

ARTICLE IV

Miscellaneous Provisions

Section 4.1          Survival of Representations and Warranties.  The agreements of the Company, as set forth herein, and the respective representations and warranties of Holder and the Company as set forth herein in Articles 2 and 3, respectively, shall survive the Closing Date.

Section 4.2          Notice.  Any notice provided for in this Agreement shall be in writing and shall be either personally delivered, or mailed first class mail (postage prepaid) with return receipt requested or sent by reputable overnight courier service (charges prepaid):

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(a)         if to the Holder, at its address as follows:

Zimmer Partners, LP

888 Seventh Avenue, 23^rd Floor

New York, NY 10106

Attention:  General Counsel

(b)         if to the Company, at its address, as follows:

Emerald Oil, Inc.
200 Columbine, Suite 500
Denver, Colorado 80206
Attention: General Counsel

Each party hereto by notice to the other party may designate additional or different addresses for subsequent notices or communications. All notices and communications will be deemed to have been duly given: at the time delivered by hand, if personally delivered; five business days after being deposited in the mail, postage prepaid, if mailed; when receipt acknowledged, if transmitted by facsimile; and the next business day after timely delivery to the courier, if sent by overnight air courier guaranteeing next day delivery.

Section 4.3          Entire Agreement.  This Agreement and the other documents and agreements executed in connection with the Exchange embody the entire agreement and understanding of the parties hereto with respect to the subject matter hereof and supersede all prior and contemporaneous oral or written agreements, representations, warranties, contracts, correspondence, conversations, memoranda and understandings between or among the parties or any of their agents, representatives or affiliates relative to such subject matter, including, without limitation, any term sheets, emails or draft documents.

Section 4.4          Assignment; Binding Agreement.  This Agreement and the various rights and obligations arising hereunder shall inure to the benefit of and be binding upon the parties hereto and their successors and assigns.

Section 4.5          Counterparts.  This Agreement may be executed in multiple counterparts, and on separate counterparts, each of which shall be deemed an original, but all of which taken together shall constitute one and the same instrument. Any counterpart or other signature hereupon delivered by facsimile shall be deemed for all purposes as constituting good and valid execution and delivery of this Agreement by such party.

Section 4.6          Remedies Cumulative.  Except as otherwise provided herein, all rights and remedies of the parties under this Agreement are cumulative and without prejudice to any other rights or remedies available at law.

Section 4.7          Governing Law.  This Agreement shall in all respects be construed in accordance with and governed by the substantive laws of the State of Delaware, without reference to its conflicts of law rules.  Any right to trial by jury with respect to any action or proceeding arising in connection with this Agreement is hereby waived by the parties hereto.  The Company and the Holder agree that any suit or proceeding arising in respect of this Agreement will be tried exclusively in the U.S. District Court for the District of Delaware, and the Company and the Holder agree to submit to the jurisdiction of, and to venue in, such court.

Section 4.8          No Third Party Beneficiaries or Other Rights.  Nothing herein shall grant to or create in any person not a party hereto, or any such person’s dependents or heirs, any right to any benefits hereunder, and no such party shall be entitled to sue any party to this Agreement with respect thereto.

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Section 4.9          Waiver; Consent.  This Agreement may not be changed, amended, terminated, augmented, rescinded or discharged (other than in accordance with its terms), in whole or in part, except by a writing executed by the parties hereto. No waiver of any of the provisions or conditions of this Agreement or any of the rights of a party hereto shall be effective or binding unless such waiver shall be in writing and signed by the party claimed to have given or consented thereto. Except to the extent otherwise agreed in writing, no waiver of any term, condition or other provision of this Agreement, or any breach thereof shall be deemed to be a waiver of any other term, condition or provision or any breach thereof, or any subsequent breach of the same term, condition or provision, nor shall any forbearance to seek a remedy for any noncompliance or breach be deemed to be a waiver of a party’s rights and remedies with respect to such noncompliance or breach.

Section 4.10        Word Meanings.  The words such as “herein,” “hereinafter,” “hereof” and “hereunder” refer to this Agreement as a whole and not merely to a subdivision in which such words appear unless the context otherwise requires. The singular shall include the plural, and vice versa, unless the context otherwise requires. The masculine shall include the feminine and neuter, and vice versa, unless the context otherwise requires.

Section 4.11        No Broker.  Neither party has engaged any third party as broker or finder or incurred or become obligated to pay any broker’s commission or finder’s fee in connection with the transactions contemplated by this Agreement other than such fees and expenses for which that particular party shall be solely responsible.

Section 4.12        Further Assurances.  The Holder and the Company each hereby agree to execute and deliver, or cause to be executed and delivered, such other documents, instruments and agreements, and take such other actions, as either party may reasonably request in connection with the transactions contemplated by this Agreement.

Section 4.13        Costs and Expenses.  The Holder and the Company shall each pay their own respective costs and expenses incurred in connection with the negotiation, preparation, execution and performance of this Agreement, including, but not limited to, attorneys’ fees.

Section 4.14        Headings.  The headings in this Agreement are for convenience of reference only and shall not limit or otherwise affect the meaning hereof.

Section 4.15        Severability. If any one or more of the provisions contained herein, or the application thereof in any circumstance, is held invalid, illegal or unenforceable, the validity, legality and enforceability of any such provision in every other respect and of the remaining provisions contained herein shall not be affected or impaired thereby.

[the remainder of this page is intentionally left blank]

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IN WITNESS WHEREOF, each of the parties hereto has caused this Agreement to be executed as of the date first above written.

HOLDER:
By:	/s Stuart J. Zimmer
Name: Stuart J. Zimmer
Title: Authorized Signatory, Investment Manager to ZP Master Utility Fund, Ltd. and P Zimmer Ltd.
EMERALD OIL, INC.
By:	/s/ McAndrew A. Rudisill
Name: McAndrew A. Rudisill
Title: Chief Executive Officer and President

Signature Page to Exchange Agreement

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EX-10.3

Exhibit 10.3

LIMITED FORBEARANCE AGREEMENT

This LIMITED FORBEARANCE AGREEMENT (this “Agreement”), dated as of November 5, 2015 (the “Effective Date”), is by and among Emerald Oil, Inc., a Delaware corporation (“Borrower”), the subsidiaries of Borrower party hereto (each a “Guarantor,” and together with Borrower, “Obligors”), the Lenders (as defined below) party hereto, and Wells Fargo Bank, N.A., as administrative agent (in such capacity, “Administrative Agent”) for Lenders.

RECITALS:

A.           The Loan Documents. Obligors are indebted to Lenders and granted collateral security as evidenced by certain instruments, agreements and documents including, without limitation, the Amended and Restated Credit Agreement dated as of May 1, 2014 among Borrower, Administrative Agent, and the financial institutions party thereto from time to time, as lenders ( “Lenders”), as amended by that certain First Amendment to Credit Agreement dated September 2, 2014 and that certain Limited Waiver and Second Amendment to Credit Agreement dated April 30, 2015 (collectively, and as further amended, modified or supplemented, the “Credit Agreement”), and the other Loan Documents (as defined in the Credit Agreement); such indebtedness being secured by perfected, first priority security interests in and liens on substantially all property of Obligors (the “Collateral”) as provided in the Security Instruments (as defined in the Credit Agreement).

B.           Guaranties. All of the Secured Obligations (as defined in the Credit Agreement) have been unconditionally guaranteed by Guarantors pursuant to certain agreements and documents including, without limitation, the Guaranty and Collateral Agreement dated November 20, 2012, by Borrower and Guarantors in favor of the Administrative Agent, as amended by that certain First Amendment to Guaranty and Collateral Agreement dated May 1, 2014 and as supplemented by that certain Assumption Agreement and Supplement dated November 24, 2014 and as supplemented by that certain Assumption Agreement dated July 28, 2015 (collectively, and as amended, modified or supplemented, the “Guaranties”).

C.           Existing Defaults. Obligors acknowledge that Events of Default under the Loan Documents have occurred and are continuing, and prospective Events of Default are anticipated to occur, each as more specifically described in Exhibit A attached hereto (the “Specified Defaults”).

D.           Forbearance Request by Borrower and Guarantors. Obligors have requested that Administrative Agent and Lenders forbear until December 18, 2015 from exercising their rights and remedies arising as a result of the occurrence of the Specified Defaults in order to allow Obligors sufficient time to improve their liquidity and business operations. Administrative Agent and the Lenders party hereto are willing to grant such forbearance subject to the terms and conditions of this Agreement.

NOW, THEREFORE, in consideration of the premises and the mutual covenants, representations, warranties and agreements contained herein, and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:

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AGREEMENTS:

1.          Definitions. Capitalized terms used and not otherwise defined herein shall have the same meanings as set forth in the Credit Agreement. In addition, the following terms, for the purposes of this Agreement, shall have the following meanings:

(a)          “Forbearance Period” means the period commencing on the Effective Date and continuing through and including the Termination Date, unless earlier terminated pursuant to the terms and provisions of this Agreement.

(b)          “Material Contracts” means any contract involving payments to or from any Obligor in an aggregate amount in excess of $5,000,000.00 including, without limitation, those listed on Exhibit B attached hereto.

(c)          “Net Cash Proceeds” means, with respect to any incurrence of Debt or sale or disposition of (including Casualty Events affecting) Oil and Gas Properties, the cash proceeds of such incurrence, sale or disposition net of reasonable legal fees, accountants’ fees, underwriters’ or placement agents’ fees, listing fees, discounts or commissions and brokerage, consultant and other customary fees and charges actually incurred in connection with such incurrence, sale or disposition and net of taxes paid or payable as a result of such incurrence, sale or disposition (after taking into account any available tax credit or deduction and any tax sharing arrangements).

(d)          “Termination Date” means 5:00 p.m. (Dallas, Texas Time) on December 18, 2015.

(e)          “Termination Event” means the occurrence of any of the following: (i) any representation or warranty made or deemed made by any Obligor in this Agreement shall be false, misleading or erroneous in any material respect when made or deemed to have been made, (ii) any Obligor shall fail to perform, observe or comply timely with any covenant, agreement or term contained in this Agreement, (iii) any Default or Event of Default, other than the Specified Defaults, shall occur or shall have occurred under this Agreement or any of the Loan Documents, (iv) any Obligor shall commence a voluntary proceeding seeking liquidation, reorganization, or other relief with respect to itself or its debts under any bankruptcy, insolvency, or other similar law now or hereafter in effect or seeking the appointment of a trustee, receiver, liquidator, custodian, or other similar official of it or a substantial part of its property or shall consent to any such relief or to the appointment of or taking possession by any such official in an involuntary case or other proceeding commenced against it or shall make a general assignment for the benefit of creditors or shall generally fail to pay its debts as they become due or shall take any action to authorize any of the foregoing, (v) an involuntary proceeding shall be commenced against any Obligor seeking liquidation, reorganization, or other relief with respect to it or its debts under any bankruptcy, insolvency, or other similar law now or hereafter in effect or seeking the appointment of a trustee, receiver, liquidator, custodian, or other similar official for it or a substantial part of its property, in each case that remains undismissed or unstayed for five (5) consecutive calendar days, (vi) any event or condition shall occur after the Effective Date which shall have a Material Adverse Effect, as determined by Administrative Agent, (vii) any default or event of default shall occur after the Effective Date in connection with any Material Contract, or (viii) the exercise by any creditor or holder of Material Indebtedness of any Obligor (excluding the Credit Parties under the Loan Documents) of any right or remedy available to them in connection with any default under the documents governing such Material Indebtedness, including, but not limited to any foreclosure or enforcement action against any Collateral.

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2.          Forbearance.

(a)          Forbearance. Subject to the terms of this Agreement and only so long as no Termination Event shall have occurred, Administrative Agent and Lenders hereby agree to forbear until the Termination Date from exercising their rights and remedies under the Loan Documents arising from Specified Defaults. Notwithstanding the foregoing, the forbearance granted by the Administrative Agent and Lenders pursuant hereto shall not constitute and shall not be deemed to constitute a waiver of any of the Specified Defaults or of any other Default or Event of Default under the Loan Documents. On and after the Termination Date, or such earlier date on which a Termination Event occurs, Administrative Agent’s and Lenders’ agreement hereunder to forbear shall terminate automatically without further act or action by Administrative Agent or Lenders, and Administrative Agent and Lenders shall be entitled to exercise any and all rights and remedies available to it or them under the Loan Documents and this Agreement, at law, in equity, or otherwise.

(b)          Principal and Interest Payments; Borrowings. Commencing on the Effective Date, Borrower shall pay to Administrative Agent, for the benefit of the Lenders on a pro rata basis accrued interest on the outstanding principal balance of the Loans on the last Business Day of each calendar month. Commencing on the Effective Date, interest shall accrue and be payable on the outstanding principal balance of the Loans at a rate per annum equal to one and three quarters percent (1.75%) plus the Alternate Base Rate, but in no event to exceed the Highest Lawful Rate. During the Forbearance Period, no outstanding Loans may be continued as, or converted into, Eurodollar Loans, no Lender has any obligation to make additional Loans, and Issuing Bank has no obligation to issue any Letter of Credit.

(c)          Other Payments. Borrower shall pay Administrative Agent, for the benefit of those Lenders that deliver fully executed signature pages to this Agreement to the Administrative Agent on or before 5:00 p.m. on November 5, 2015, a fully earned forbearance fee equal to one half of one percent (0.5%) of the outstanding principal balance of the Loans owing to each such Lender as of the Effective Date, of which fifteen hundredths of one percent (0.15%) of such outstanding principal balance (the “Initial Forbearance Fee Payment”), shall be paid on the Effective Date, and the remaining balance of which shall be paid at the expiration or termination of the Forbearance Period (provided that the remaining balance shall be waived in the event Borrower has repaid all outstanding Loans in full on or before the expiration or termination of the Forbearance Period). Borrower also agrees to reimburse Administrative Agent and the Lenders upon demand for all out-of-pocket expenses (including reasonable attorneys’ fees, settlement costs and fees and expenses of FTI Consulting, Inc., (“FTI”) as the financial advisor engaged by Administrative Agent’s counsel) incurred in connection with the negotiation of this Agreement, any further restructuring or “workout” with Obligors, whether or not consummated, of any Secured Obligations, and any enforcement of any Secured Obligations. Borrower acknowledges and agrees that all such expenses are being incurred in connection with a restructuring or workout, as these terms are used in Section 12.03(a) of the Credit Agreement.

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3.          Representations and Warranties. To induce Administrative Agent and Lenders to enter into this Agreement, Obligors hereby jointly and severally represent and warrant to Credit Parties as follows:

(a)          Duly Organized. Obligors are duly organized, validly existing and in good standing under the laws of the jurisdiction in which they were organized and formed, and Obligors have the power and authority to perform their respective obligations under this Agreement and the Loan Documents.

(b)          Authority. The execution, delivery and performance of this Agreement (i) have been duly authorized by all requisite action on the part of Obligors and (ii) do not and will not violate the organizational documents of Obligors, any other material agreement to which any Obligor is a party, or any law, rule or regulation, or any order of any court, governmental authority or arbitrator, by which any Obligor or any of its respective properties is bound.

(c)          No Defenses. The outstanding principal balance of the Loans is $139,604,977.84 as of the Effective Date. None of Obligors has any defenses to payment, counterclaims, or rights of setoff with respect to the Loans or any other Secured Obligations existing as of the Effective Date.

(d)          No Other Defaults. Except for the Specified Defaults, no Default or Event of Default under the Loan Documents has occurred and is continuing.

(e)          Deposit Accounts. Upon and after the Effective Date, all of Obligors’ deposit accounts are maintained with Wells Fargo Bank, N.A. and are covered by a deposit account control agreement in form and substance acceptable to Administrative Agent.

(f)          Taxes. All payments due to all taxing authorities with respect to the Collateral are current as of the Effective Date.

4.          Covenants. Notwithstanding any provisions to the contrary contained in the Loan Documents, Obligors hereby covenant and agree that, during the Forbearance Period, each of them will perform, observe and comply with each of the following covenants:

(a)          Compliance with Related Documents and this Agreement. Obligors will perform, observe and comply with each covenant, agreement and term contained in this Agreement and each of the Loan Documents, including, without limitation, the fees and payments required thereunder, except for the Specified Defaults.

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(b)          Prepayment of Loans. Borrower shall make a mandatory prepayment of the Loans in an amount equal to 100% of the Net Cash Proceeds received by any Obligor in each of the following circumstances:

(1)         If any Obligor sells, assigns, farms out, conveys or otherwise transfers any Oil and Gas Properties (or any Equity Interests in any Obligor owning such Oil and Gas Properties) other than the Title Defect Properties (as defined in that certain Letter Agreement dated October 1, 2015 among the Administrative Agent, the Majority Lenders, the Borrower and the Guarantors) or terminates, unwinds, cancels or otherwise disposes of any Swap Agreement, and the Net Cash Proceeds of all such transfers (other than fifty percent (50%) of proceeds from the transfer of Title Defect Properties) and all such terminations of Swap Agreements made since the commencement of the Forbearance Period exceed $500,000.00;

(2)         If any Obligor issues any Debt for borrowed money since the commencement of the Forbearance Period; or

(3)         If any Obligor receives a tax refund, insurance proceeds or other recoveries for a Casualty Event (collectively, “Recoveries”), and the aggregate amount of the Recoveries since the commencement of the Forbearance Period exceeds $500,000.00.

(c)          Deposit of Funds. Obligors shall cause all of their collections, including but not limited to joint interest billing receivables and hedge settlements, to be deposited in deposit accounts that are covered by a deposit account control agreement in favor of Administrative Agent, and shall not open or maintain any deposit account other than deposit accounts that are maintained with Wells Fargo Bank, N.A.

(d)          Financial Statements. Borrower shall deliver to Administrative Agent and Lenders, no later than twenty (20) days after the end of each calendar month, a copy of the unaudited consolidated balance sheet for Borrower and its Consolidated Subsidiaries and related statements of operations, stockholders’ equity, as applicable, and cash flows as of the end of and for such calendar month and the then elapsed portion of the fiscal year. Such financial statements shall be certified by one of Borrower’s Financial Officers as presenting fairly, in all material respects, the financial condition and results of operations of Borrower and its Consolidated Subsidiaries on a consolidated basis in accordance with GAAP consistently applied, subject to normal year-end audit adjustments and the absence of footnotes.

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(e)          Cash Flow Forecasts. Borrower shall deliver to Administrative Agent and Lenders, by no later than 12 noon Central Time on Thursday of each week beginning on the first Thursday after the Effective Date, an updated weekly 13-week cash flow forecast setting forth all sources and uses of cash and beginning and ending cash balances (the “Budget”), an initial copy of which shall be delivered on or prior to the Effective Date. For each monthly period set forth in the Budget, the actual production volume of crude oil shall not in any event be less than the amount forecasted for such period by more than ten percent (10%) of the amount forecasted. For each weekly period set forth in the Budget, the actual expenditures by Obligors for Total Operating Disbursements (as designated in the Budget) shall not in any event exceed the aggregate amount budgeted for such period by more than fifteen percent (15%) of the budgeted amount, and the actual expenditures of Obligors shall not, for each line item in the Budget labeled Accounts Payable – Critical, Accounts Payable – DMS, Salaries & Benefits, Rent & Utilities and Other exceed the amount budgeted for such line item in the Budget for such period by more than twenty percent (20%) of the budgeted amount. With respect to only the line item labeled Accounts Payable – Critical, Borrower may carry over unspent budgeted amounts in any weekly period to future weekly periods so that Borrower has available to it the cumulative-to-date total budgeted amounts at any time, without causing such future weekly periods to exceed the allowable variance. Any such carryover spend will also be deducted in determining the Borrower’s compliance with expenditures for Total Operating Disbursements. Obligors shall operate strictly in accordance with the Budget and shall pay only those actual, ordinary and necessary operating expenses of Obligors’ business in compliance with the Budget (subject to the variances identified above).

(f)          Reconciliation Reports. Borrower shall deliver to Administrative Agent and Lenders concurrently with each Budget (i) a variance report reconciling the prior week’s cash flow forecast to the actual sources and uses of cash for the prior week, along with a line-by-line reconciliation and explanation of material variances, and (ii) a listing of each Obligor’s accounts receivable, including invoices aged by invoice date and due date (with an explanation of the terms offered), together with a summary specifying the name, address, and balance due for each account debtor, and a schedule and aging of each Obligor’s accounts payable.

(g)          Mortgaged Properties. Obligors shall cooperate with Administrative Agent and Lenders to cause the Mortgaged Properties and the title information relating thereto delivered to Administrative Agent to exceed in each case 95% of the total value of the Oil and Gas Properties evaluated by the most recent Reserve Report and shall deliver to Administrative Agent all information and take all actions reasonably requested by Administrative Agent to assure compliance therewith.

(h)          Minimum Cash. Obligors will cause their Cash Equivalents not to be less than $1,000,000.00 at the end of each week, as reported to Administrative Agent and Lenders in accordance with Section 4(e) of this Agreement, during the Forbearance Period.

(i)          Maximum Capital Expenditures. Obligors will cause their capital expenditures not to exceed $300,000.00 during the Forbearance Period.

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(j)          Notices. Borrower will give Administrative Agent prompt written notice of the following:

(1) Any notice of a default or required redemption relating to any Material Indebtedness of any Obligor;

(2) The occurrence of any default or event of default, or the pursuit of any remedies against any Obligor, in connection with any of the Material Contracts;

(3) Any actual or threatened suspension of services by the providers of Borrower’s midstream and gathering services or any other adverse development in Borrower’s relationship with such providers;

(4) The filing or commencement of, or the threat in writing of, any action, suit (whether in state or federal court), proceeding, receivership, involuntary petition in bankruptcy, investigation or arbitration by or before any arbitrator or Governmental Authority pending against or, to the knowledge of the Borrower, threatened against or affecting any of the Obligors not previously disclosed in writing to Lenders or any material adverse development in any action, suit, proceeding, investigation or arbitration (whether or not previously disclosed to Lenders); and

(5) Any notice of the filing or recordation of a mechanic’s, materialmen’s or other like Lien received by any of the Obligors with respect to any of their Oil and Gas Properties.

(k)          Information. Obligors shall cooperate with FTI in performing its work as financial advisor to Administrative Agent and its counsel. In addition to any notices required to be given under the Loan Documents, Obligors and their Advisors will provide Administrative Agent, Lenders and FTI with such other information as may be requested by Administrative Agent or FTI from time to time, within five (5) Business Days of such request, including, without limitation, copies of any bank or other financial institution statements; financial statements; accounts receivable and accounts payable agings; transactional documentation; litigation pleadings, depositions, related documents and transcripts; letters of intent or offers to purchase, lease or license any portion, all or substantially all of the assets or ownership interests of any of Obligors; and letters of intent or commitments for any capital investment, loan or other financing in or to any of Obligors, except, in each case, to the extent expressly designated as confidential and not to be disclosed to Obligors’ secured lenders. Borrower hereby acknowledges Administrative Agent’s right under the Credit Agreement to engage FTI in its sole discretion under these circumstances and agrees to reimburse Administrative Agent for the fees and expenses of FTI as provided in Section 2(c).

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(l)          Access. Administrative Agent, FTI, Lenders, and their agents shall have access during normal business hours to Obligors’ business premises and to the Collateral to review, appraise and evaluate the physical condition of the Collateral and to inspect the books, records and reports of Obligors concerning the operation of Obligors’ businesses, financial condition, the transfers and expenditures of funds generated therefrom, the accrual of expenses relating thereto, and any and all other records relating to the operations of Obligors. Obligors and their Advisors will fully cooperate with Administrative Agent, Lenders and FTI regarding such reviews, evaluations, and inspections, and Obligors shall make their employees, consultants and professionals reasonably available to Administrative Agent, Lenders, FTI, and Administrative Agent’s other professionals and consultants in conducting such reviews, evaluations, and inspections.

(m)          No Control. No act committed or action taken by the Credit Parties under this Agreement or the Loan Documents will be used, construed, or deemed to hold the Credit Parties to be in control of any Obligor, or the governance, management or operations of any Obligor for any purpose, without limitation, or to be participating in the management of any Obligor or acting as a “responsible person” or “owner or operator” or a person in “control” with respect to the governance, management or operation of any Obligor or their respective businesses (as such terms, or any similar terms, are used in the U.S. Bankruptcy Code, the Code, or CERCLA, each as may be amended from time to time, or any other federal or state statute, at law, in equity, or otherwise) by virtue of the interests, rights, and remedies granted to or conferred upon the Credit Parties under this Agreement or the Loan Documents.

(n)          Obligors’ Advisors. Obligors shall maintain their engagement of Opportune LLP and Intrepid Financial Partners, or in the event either such engagement shall terminate, such replacement advisors of comparable standing and reputation to which Administrative Agent may consent in writing, such consent not to be unreasonably withheld (collectively, the “Advisors”) at all times during the Forbearance Period. Obligors authorize Administrative Agent, FTI, and their agents and professionals to communicate with Obligors’ Advisors without notice to, or the presence of, Obligors.

The failure of Obligors to timely comply with the terms of this Section 4 shall constitute (i) a Default and an Event of Default under and for all purposes of the Credit Agreement, and (ii) a Termination Event hereunder.

5.          Conditions Precedent. As a condition to the commencement of the Forbearance Period on the Effective Date, each of the following conditions shall have been fulfilled by Obligors:

(a)          This Agreement. The Obligors, the Administrative Agent and the Majority Lenders have each executed and delivered this Agreement.

(b)          Payments. Borrower shall have paid in cash (i) all accrued and unpaid interest on the outstanding principal balance of the Loans, (ii) the Initial Forbearance Fee Payment, (iii) $100,000 to serve as FTI’s retainer, and (iv) all invoiced and unpaid fees and expenses reasonably incurred by and owing to Administrative Agent’s counsel, Vinson & Elkins L.L.P.;

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(c)          Budget. Borrower shall have delivered the initial Budget, together with an aging of each Obligor’s receivables and payables in accordance with Section 4(f) of this Agreement;

(d)          Deposit Accounts. Obligors and Wells Fargo Bank, N.A., as depositary, shall have entered into one or more deposit account control agreements with Administrative Agent covering the accounts maintained by the Obligors with Wells Fargo Bank, N.A.;

(e)          Zavanna Settlement. Borrower shall have obtained the consent of Majority Lenders to the Confidential Settlement Agreement dated October 16, 2015 among Borrower, Emerald WB LLC and Zavanna, LLC, and the release of Administrative Agent’s Lien in the Mortgaged Properties contemplated thereby; and

(f)          Evidence of Authority. Obligors shall have delivered to Administrative Agent certificates of duly authorized officers of Obligors, and such other documents, instruments and agreements as Administrative Agent shall require, to evidence the due authorization, execution and delivery of this Agreement, each of which shall be in form and substance satisfactory to Administrative Agent.

The failure of Obligors to timely comply with the terms of this Section 5 shall constitute (i) a Default and an Event of Default under and for all purposes of the Credit Agreement, and (ii) a Termination Event hereunder.

6.          Ratification of Related Documents and Collateral. Obligors hereby acknowledge that each of them has received from Administrative Agent proper notice of Default with respect to the Specified Defaults. Each of the Obligors hereby waives (a) any further notice of Default, notice of intent to accelerate, or demand for payment and (b) any further opportunity to cure any of the Specified Defaults. Except as modified by this Agreement, each Obligor hereby acknowledges, ratifies, reaffirms, and agrees that each of the Loan Documents, and the first priority, perfected liens and security interests created thereby in favor of Administrative Agent in the Collateral, are and will remain in full force and effect and binding on Obligors, and are enforceable in accordance with their respective terms and applicable law. Each of the Obligors acknowledges, ratifies, and reaffirms all of the terms and provisions of the Loan Documents, except as modified herein, which are incorporated by reference as of the Effective Date as if set forth herein including, without limitation, all promises, agreements, warranties, representations, covenants, releases, indemnifications, and waivers of jury trials contained therein. Obligors hereby acknowledge, ratify, and confirm the Credit Agreement, the Notes, the Security Instruments, the Guaranties, the other Loan Documents, and all of their respective debts and obligations to Credit Parties thereunder. Obligors acknowledge and agree that in the event Administrative Agent seeks to take possession of any or all of the Collateral securing any of the Secured Obligations by court process, Obligors each irrevocably waive, to the fullest extent permitted by law, any bonds and any surety or security relating thereto required by any statute, court rule or otherwise as an incident to such possession.

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7.          Remedies Upon Termination Event. Upon the occurrence of a Termination Event, (a) the Forbearance Period will terminate without further act or action by any Credit Party, (b) Administrative Agent will be entitled immediately to accelerate the Secured Obligations, institute foreclosure proceedings against the Collateral and to exercise any and all of Credit Parties’ rights and remedies available to Credit Parties under the Loan Documents and this Agreement, at law, in equity, or otherwise, without further opportunity to cure, demand, presentment, notice of dishonor, notice of Default, notice of intent to accelerate, notice of intent to foreclose, notice of protest or other formalities of any kind, all of which are hereby expressly waived by Obligors.

8.          Acknowledgment of Defaults. Obligors specifically acknowledge the existence and continuation of the Specified Defaults.

9.          WAIVER AND RELEASE. EACH OF Obligors (IN ITS OWN RIGHT AND ON BEHALF OF ITS PREDECESSORS, SUCCESSORS, LEGAL REPRESENTATIVES AND ASSIGNS) HEREBY EXPRESSLY AND UNCONDITIONALLY ACKNOWLEDGES AND AGREES THAT IT HAS NO SETOFFS, COUNTERCLAIMS, ADJUSTMENTS, RECOUPMENTS, DEFENSES, CLAIMS, CAUSES OF ACTION, ACTIONS OR DAMAGES OF ANY CHARACTER OR NATURE, WHETHER CONTINGENT, NONCONTINGENT, LIQUIDATED, UNLIQUIDATED, FIXED, MATURED, UNMATURED, DISPUTED, UNDISPUTED, LEGAL, EQUITABLE, SECURED OR UNSECURED, KNOWN OR UNKNOWN, ACTUAL OR PUNITIVE, FORESEEN OR UNFORESEEN, DIRECT, OR INDIRECT, AGAINST any CREDIT Party, ANY OF ITS AFFILIATES OR ANY OF ITS OFFICERS, DIRECTORS, AGENTS, EMPLOYEES, ATTORNEYS OR REPRESENTATIVES OR ANY OF THEIR RESPECTIVE PREDECESSORS, SUCCESSORS OR ASSIGNS (COLLECTIVELY, THE “LENDER-RELATED PARTIES”) OR ANY GROUNDS OR CAUSE FOR REDUCTION, MODIFICATION, SET ASIDE OR SUBORDINATION OF THE SECURED Obligations OR ANY LIENS OR SECURITY INTERESTS OF the CREDIT Parties. IN PARTIAL CONSIDERATION FOR THE AGREEMENT OF Administrative Agent and LENDERs TO ENTER INTO THIS AGREEMENT, EACH OF Obligors HEREBY KNOWINGLY AND UNCONDITIONALLY WAIVES AND FULLY AND FINALLY RELEASES AND FOREVER DISCHARGES THE LENDER-RELATED PARTIES FROM, and covenants not to sue the Lender-related parties for, ANY AND ALL SETOFFS, COUNTERCLAIMS, ADJUSTMENTS, RECOUPMENTS, CLAIMS, CAUSES OF ACTION, ACTIONS, GROUNDS, CAUSES, DAMAGES, COSTS AND EXPENSES OF EVERY NATURE AND CHARACTER, WHETHER CONTINGENT, NONCONTINGENT, LIQUIDATED, UNLIQUIDATED, FIXED, MATURED, UNMATURED, DISPUTED, UNDISPUTED, LEGAL, EQUITABLE, SECURED OR UNSECURED, KNOWN OR UNKNOWN, ACTUAL OR PUNITIVE, FORESEEN OR UNFORESEEN, DIRECT OR INDIRECT, ARISING OUT OF OR FROM OR RELATED TO ANY OF THE LOAN DOCUMENTS, WHICH any Obligor NOW OWNS AND HOLDS, OR HAS AT ANY TIME HERETOFORE OWNED OR HELD, SUCH WAIVER, RELEASE AND DISCHARGE BEING MADE WITH FULL KNOWLEDGE AND UNDERSTANDING OF THE CIRCUMSTANCES AND EFFECTS OF SUCH WAIVER, RELEASE AND DISCHARGE AND AFTER HAVING CONSULTED LEGAL COUNSEL OF ITS OWN CHOOSING WITH RESPECT THERETO. THIS SECTION IS IN ADDITION TO ANY OTHER RELEASE OF ANY OF THE LENDER-RELATED PARTIES BY ANY OF Obligors AND SHALL NOT IN ANY WAY LIMIT ANY OTHER RELEASE, COVENANT NOT TO SUE, OR WAIVER BY ANY OF Obligors IN FAVOR OF ANY OF THE LENDER-RELATED PARTIES.

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10.         No Obligation of Credit Parties. Obligors hereby acknowledge and understand that upon the expiration or termination of the Forbearance Period, if all the Specified Defaults have not been cured or waived by written agreement in accordance with the Credit Agreement, or if there shall at such time exist a Default or Event of Default, then Credit Parties shall have the right to proceed to exercise any or all available rights and remedies, which may include foreclosure on the Collateral and/or institution of legal proceedings. Credit Parties shall have no obligation whatsoever to extend the maturity of the Secured Obligations, waive any Events of Default or Defaults, defer any payments, or further forbear from exercising its rights and remedies.

11.         No Implied Waivers. No failure or delay on the part of Credit Parties in exercising, and no course of dealing with respect to, any right, power or privilege under this Agreement, the Credit Agreement, the Notes, the Security Instruments, the Guaranties, or any other Loan Document shall operate as a waiver thereof, nor shall any single or partial exercise of any right, power or privilege under this Agreement, the Credit Agreement, the Notes, the Guaranties, or any other Loan Document preclude any other or further exercise thereof or the exercise of any other right, power or privilege.

12.         INDEMNIFICATION. IN ADDITION TO, AND WITHOUT LIMITATION OF, ANY AND ALL INDEMNITIES PROVIDED IN THE LOAN DOCUMENTS, Obligors HEREBY, JOINTLY AND SEVERALLY, INDEMNIFY AND HOLD EACH OF THE LENDER-RELATED PARTIES HARMLESS FROM AND AGAINST ANY AND ALL CLAIMS, LIABILITies, LOSSES, DAMAGES, CAUSES OF ACTION, SUITS, JUDGMENTS, COSTS, AND EXPENSES, INCLUDING, WITHOUT LIMITATION, Reasonable ATTORNEYS’ FEES, ARISING OUT OF OR FROM OR RELATED TO ANY OF THE LOAN DOCUMENTS OR THIS AGREEMENT. IF ANY ACTION, SUIT, OR PROCEEDING IS BROUGHT AGAINST ANY OF THE LENDER-RELATED PARTIES, Obligors SHALL, AT Such Lender-Related Parties’ REQUEST, DEFEND THE SAME AT THEIR SOLE COST AND EXPENSE, SUCH COST AND EXPENSE TO BE A JOINT AND SEVERAL LIABILITY OF Obligors, BY COUNSEL SELECTED BY such Lender-related Party. NOTWITHSTANDING ANY PROVISION OF THIS AGREEMENT OR ANY OTHER LOAN DOCUMENT, THIS SECTION 12 SHALL REMAIN IN FULL FORCE AND EFFECT AND SHALL SURVIVE ANY DELIVERY AND PAYMENT ON THE SECURED Obligations, THIS AGREEMENT AND THE OTHER LOAN DOCUMENTS.

13.         Survival of Representations and Warranties. All representations and warranties made in this Agreement or any other Loan Document will survive the execution and delivery of this Agreement, and no investigation by Credit Parties or any closing will affect the representations and warranties or the right of Credit Parties to rely upon them.

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14.         Review and Construction of Documents. Each of the Obligors hereby acknowledges, represents, and warrants to Credit Parties that (a) Obligors have had the opportunity to consult with legal counsel of their own choice and have been afforded an opportunity to review this Agreement with their legal counsel, (b) Obligors have reviewed this Agreement and fully understand the effects thereof and all terms and provisions contained herein, and (c) Obligors have executed this Agreement of their own free will and volition. The recitals contained in this Agreement shall be construed to be part of the operative terms and provisions of this Agreement.

15.         ENTIRE AGREEMENT; AMENDMENT. THIS AGREEMENT AND THE RELATED DOCUMENTS AS INCORPORATED HEREIN EMBODY THE FINAL, ENTIRE AGREEMENT BETWEEN THE PARTIES HERETO REGARDING Administrative Agent’s and Lenders’ FORBEARANCE WITH RESPECT TO THEIR RIGHTS AND REMEDIES ARISING AS A RESULT OF THE SPECIFIED DEFAULTS AND SUPERSEDE ANY AND ALL PRIOR COMMITMENTS, AGREEMENTS, REPRESENTATIONS AND UNDERSTANDINGS, WHETHER WRITTEN OR ORAL, RELATING TO THE SUBJECT MATTER HEREOF AND MAY NOT BE CONTRADICTED OR VARIED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR SUBSEQUENT ORAL AGREEMENTS OR DISCUSSIONS OF THE PARTIES HERETO. THERE ARE NO ORAL AGREEMENTS AMONG THE PARTIES HERETO. The provisions of this Agreement may be amended or waived only by an instrument in writing signed by the parties hereto. The Loan Documents, as modified by this Agreement, continue to evidence the agreement of the parties with respect to the subject matter thereof.

16.         Notices. All notices, requests, demands and other communications under this Agreement will be given in accordance with the provisions of the Credit Agreement, except that notices to Administrative Agent shall be given to the following:

Wells Fargo Bank, N.A.

MAC D1053-150

301 S. College Street

Charlotte, NC 28288

Attention: Michael J. Thomas

Fax: 704.383.7611

Email: mjthomas@wellsfargo.com

17.         Successors and Assigns. This Agreement will be binding upon, and will inure to the benefit of, the parties hereto and their respective successors and assigns, provided that none of Obligors may assign any rights or obligations under this Agreement without the prior written consent of Administrative Agent.

18.         Tolling of Statutes of Limitation. The parties hereto agree that all applicable statutes of limitations with respect to the Loan Documents shall be tolled and not begin running until the Termination Date.

19.         Arms-Length/Good Faith. This Agreement has been negotiated at arms-length and in good faith by the parties hereto.

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20.         Governing Law. This Agreement shall be governed by and construed in accordance with the laws of the State of New York and applicable laws of the United States of America.

21.         Interpretation. Wherever the context hereof will so require, the singular shall include the plural, the masculine gender shall include the feminine gender and the neuter and vice versa. The headings, captions and arrangements used in this Agreement are for convenience only and shall not affect the interpretation of this Agreement.

22.         Severability. In case any one or more of the provisions contained in this Agreement shall for any reason be held to be invalid, illegal or unenforceable in any respect, such invalidity, illegality, or unenforceability shall not affect any other provision hereof, and this Agreement shall be construed as if such invalid, illegal, or unenforceable provision had never been contained herein.

23.         Counterparts. This Agreement may be executed and delivered in any number of counterparts, and by different parties hereto on separate counterparts, each of which when so executed and delivered shall be deemed to be an original and all of which counterparts taken together shall constitute one and the same instrument; provided that no party shall be bound by this Agreement until each of the parties has executed a counterpart hereof. Execution of this Agreement via facsimile or other electronic means shall be effective, and signatures received via facsimile or other electronic means shall be binding upon the parties hereto and shall be effective as originals.

24.         Further Assurances. Obligors each agree to execute, acknowledge, deliver, file and record such further certificates, instruments and documents, and to do all other acts and things, as may be reasonably requested by Administrative Agent as necessary or advisable to carry out the intents and purposes of this Agreement.

25.         Loan Document. This Agreement is a Loan Document for all purposes of the Credit Agreement and the other Loan Documents.

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IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the Effective Date.

BORROWER:
EMERALD OIL, INC., a Delaware corporation
By:	/s/ Ryan Smith
Name:	Ryan Smith
Title:	Chief Financial Officer
Guarantors:
EMERALD WB LLc, a Colorado limited liability company
By:	/s/ Ryan Smith
Name:	Ryan Smith
Title:	Chief Financial Officer
EMERALD dB LLc, a Delaware limited liability company
By:	/s/ Ryan Smith
Name:	Ryan Smith
Title:	Chief Financial Officer
EMERALD NWB LLc, a Delaware limited liability company
By:	/s/ Ryan Smith
Name:	Ryan Smith
Title:	Chief Financial Officer
EOX MARKETING, LLc, a Delaware limited liability company
By:	/s/ Jeremy Weemhoff
Name:	Jeremy Weemhoff
Title:	President

[Signature Page to Forbearance Agreement]

Administrative Agent and Lender:
WELLS FARGO BANK, NATIONAL ASSOCIATION, a national banking association
By:	/s/ Michael J. Thomas
Name:	Michael J. Thomas
Title:	Senior Vice President

[Signature Page to Forbearance Agreement]

Lender:

SUNTRUST BANK

By:	/s/ Janet R. Naifeh
Name:	Janet R. Naifeh
Title:	Senior Vice President

[Signature Page to Forbearance Agreement]

Lender:
THE BANK OF NOVA SCOTIA
By:	/s/ Steve Kerr
Name:	Steve Kerr
Title:	Managing Director

[Signature Page to Forbearance Agreement]

Lender:

BARCLAYS BANK PLC

By:

Name:

Title:

By:

Name:

Title:

[Signature Page to Forbearance Agreement]

Lender:

CREDIT SUISSE AG, CAYMAN ISLANDS BRANCH

By:

Name:

Title:

By:

Name:

Title:

[Signature Page to Forbearance Agreement]

Exhibit A
SPECIFIED DEFAULTS

Each of the existing and prospective breaches of the Loan Documents set forth below are Specified Defaults:

1.          The Event of Default occurring under Section 10.01(d) of the Credit Agreement as a result of a breach of Section 9.01(a) and (b) of the Credit Agreement with respect to the quarters ended June 30, 2015 and September 30, 2015.

2.          The Event of Default under Section 10.01(a) of the Credit Agreement as a result of the failure of the Borrower to repay the Borrowing Base Deficiency pursuant to Section 3.04(c)(ii) of the Credit Agreement.

3.          Any Event of Default that may occur under Section 10.01(g) of the Credit Agreement as a result of an event that would enable or permit the holders of Material Indebtedness (e.g., Convertible Notes) to cause such indebtedness to become due.

Exhibit B
MATERIAL CONTRACTS

1.          Amended and Restated Gas Dedication and Gathering Agreement between Dakota Midstream, LLC, Emerald Oil, Inc. and Emerald WB LLC, dated July 1, 2014.

2.          Amended and Restated Crude Oil Dedication & Throughput Commitment Transportation Agreement between Dakota Midstream, LLC and Dakota Energy Connection, LLC, and Emerald Oil, Inc. and Emerald WB LLC, dated July 1, 2014.

3.          Amended and Restated Water Dedication and Gathering Agreement between Dakota Fluid Solutions LLC, F/K/A Mesa Oil Services, LLC and Emerald Oil, Inc. and Emerald WB LLC, dated July 1, 2014.

4.          Industrial Water Delivery Services Agreement by and between Mesa Water Services, LLC and Emerald Oil, Inc. dated February 4, 2014.

5.          Employment Agreement by and between Emerald Oil, Inc. and McAndrew Rudisill dated January 1, 2014.

6.          Employment Agreement by and between Emerald Oil, Inc. and James Russell (J.R.) Reger dated January 1, 2014, and as amended March 31, 2014.

7.          ISDA 2002 Master Agreement by and between The Bank of Nova Scotia and Emerald Oil, Inc. dated June 20, 2014.

8.          Indenture by and between Emerald Oil, Inc. and U.S. Bank National Association (as Trustee) dated March 24, 2014 regarding the Company’s 2.00% Convertible Senior Notes Due 2019.

9.          Oilfield Services contract by and between Emerald Oil, Inc. and Liberty Oilfield Services, LLC.

10.         Sixth Amendment to Office Lease dated March 3, 2014 by and between Emerald Oil, Inc. and LBA Realty Fund II-Company IV, LLC.

EX-10.4

Exhibit 10.4

AMENDED AND RESTATED CRUDE OIL DEDICATION & THROUGHPUT

COMMITMENT TRANSPORTATION AGREEMENT

BETWEEN

DAKOTA MIDSTREAM, LLC & DAKOTA ENERGY CONNECTION, LLC

AND

EMERALD OIL, INC. & EMERALD WB LLC

AMENDED AND RESTATED CRUDE OIL DEDICATION & THROUGHPUT

COMMITMENT TRANSPORTATION AGREEMENT

THIS AMENDED AND RESTATED CRUDE OIL DEDICATION & THROUGHPUT COMMITMENT TRANSPORTATION AGREEMENT ("Agreement'') is entered into on May26 , 2015, but effective as of the 1st day of July, 2014 (the "Effective Date'') by and between DAKOTA MIDSTREAM, LLC & DAKOTA ENERGY CONNECTION, LLC (Dakota Midstream, LLC being the "Transporter prior to its March 23, 2015 assignment of interests and Dakota Energy Connection, LLC being the "Transporter" thereafter), and EMERALD OIL, INC. and EMERALD WB LLC (collectively "Producer" or "Shipper"). The terms "Producer" and "Shipper" shall also include any other Affiliates of Emerald Oil, Inc. or Emerald WB LLC that own or control leasehold interests or Crude from leasehold interests located within the Area of Dedication at any time while this Agreement remains in effect. Producer and Transporter are sometimes referred to herein individually as a "Party" and collectively as the "Parties".

RECITALS

A.          Producer is a working interest owner in certain oil and gas leases, wells, and/or lands within the area described in Exhibit "A" attached hereto and by reference made a part hereof (the "Area of Dedication "), and may acquire additional interests in oil and gas leases, and/or lands within the Area of Dedication during the term of this Agreement (such current and future interests are referred to as the "Leases").

B.           Producer desires to have Transporter receive, gather or transport and redeliver all of Crude Oil owned by Producer which is produced from the Wells (as defined herein) and Leases within the Area of Dedication.

C.           Transporter desires to receive Producer's Crude at the Receipt Points and redeliver Producer's Crude at the Delivery Points (as such terms are defined herein), utilizing the facilities constructed, owned and operated by Transporter.

D.           Emerald Oil, Inc. and Dakota Midstream, LLC entered into that certain Crude Oil Dedication & Throughput Commitment Transportation Agreement dated effective July 1, 2014, as amended by that certain Amendment No. 1 dated effective November 19, 2014 (the "Original Agreement "),and Dakota Midstream, LLC assigned its interest under the Original Agreement to its Affiliate, Dakota Energy Connection, LLC effective March 23, 2015.

E.           Transporter initiated an open season and has filed a Tariff with the Federal Energy Regulatory Commission ("FERC') based on the Original Agreement ("Original Tariff ').

E.           The Parties desire now to amend and restate the Original Agreement in its entirety, effective as of July 1, 2014, to address and incorporate additional facilities to be constructed and operated by Transporter at the request of Producer to receive Producer's Crude from the same Initial System DSUs as identified in Exhibit "B-1" herein at certain new "Infill Receipt Points" in exchange for additional consideration to Transporter, with Transporter to modify the Original Tariff as needed to conform to the changes made herein.

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F.           The Parties also desire now to name and include Emerald WB LLC as a Producer Party to this Agreement and to have Emerald WB LLC ratify the Original Agreement.

Now therefore, in consideration of the mutual covenants and agreements contained in this Agreement, the Parties agree as follows:

ARTICLE I

REPRESENTATIONS & COMMITMENTS OF PRODUCER

1.1         Producer's Representations. Producer represents and warrants to Transporter, its successors and assigns, that Producer has the right to operate the Wells listed on Exhibit "B-2" and owns and has the right to dedicate and commit for physical delivery to and gathering by Transporter, Producer's Crude, as defined in Section 1.2 below, and that Producer has constructed, intends to construct, or shall cause to be constructed, the facilities necessary, if any, to enable Producer to deliver to Transporter at the Receipt Points all of Producer's Crude, in accordance with the terms and provisions of this Agreement, as well as any other facilities committed to by Producer under this Agreement.

1.2         Dedication. Producer hereby dedicates and commits to the performance of this Agreement and all of the terms and conditions herein for the Primary Term, as defined herein, as a covenant running with the land the following: (i) all of Producer's working interest share of Crude produced from the Wells operated by Producer; and (ii) all of Producer's working interest share of Crude from wells operated by parties other than Producer in which Producer takes its share of production in kind, if applicable (collectively "Producer's Crude"). Notwithstanding the foregoing, Producer's Crude shall not include: (i) Crude subject to a prior Crude dedication as of the Effective Date of this Agreement for the minimum duration of that prior Crude dedication; (ii) Crude produced from any lands or Leases that Producer in the future acquires in the Area of Dedication that are subject to a prior Crude dedication entered into by Producer's predecessor-in-interest for the minimum duration of the prior Crude dedication; (iii) Crude from Leases that are subject to a Temporary Release (for so long as such Temporary Release remains in effect) or a Permanent Release, all in accordance with. the terms of this Agreement; and (iv) Crude produced from any Leases otherwise subject to this Agreement that are no longer held by production or upon their termination, expiration or release if such Leases are not cured, renewed, top-leased, re-acquired or newly acquired in whole or in part by Producer, its successor-in-interest, their respective Affiliates, or any of their respective officers, directors, employees, agents, or representatives. Subject to the remaining terms of this Agreement, including the rights of Producer in the event of a Temporary Release or Permanent Release, as defined herein, either exclusion applies only for the remaining minimum duration of the prior Crude dedication, Producer will take all action necessary not to extend the duration of such prior Crude dedication, and upon the expiration of that prior Crude dedication such interest will automatically be dedicated and committed hereunder. Producer shall promptly furnish Transporter with notices of the termination of all prior Crude dedication arrangements and the anticipated date of first delivery of those barrels to Transporter's Crude System. Producer covenants to deliver all of Producer's Crude to Transporter at the Receipt Points without other disposition except as otherwise provided in this Agreement.

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1.3         Producer's Reservations.

i.            Producer, as a reasonable and prudent operator, hereby expressly reserves the following rights with respect to Producer's Crude and the Leases subject hereto:

a.           The right to deliver Crude to the lessors and owners of overriding royalties or other interests in the Leases if such owners are entitled to take such Crude in kind under the terms of the Leases and other instruments creating their interests entered into (1) prior to the Effective Date, with respect to Leases owned by Producer at the Effective Date, or (2) prior to the date such Leases are acquired by Producer, with respect to Leases acquired by Producer after the Effective Date;

b.           The right to pool or unitize the Leases (or any portion thereof) with other lands and leases. In the event of any such pooling or unitization, the Agreement will cover Producer's interest in the pool or unit and the Crude attributable thereto to the extent that such interest is derived from Producer's interest in the Leases.

ii.           Producer reserves the right to operate its Leases and Wells free of any control by Transporter in such a manner as Producer, in its sole discretion, may deem advisable, including without limitation the right to enter into farmouts of any Lease subject to this Agreement, to abandon any Well and surrender any Lease. Producer reserves the right to determine the maximum efficient rate of flow for any Well (including the right to curtail production due to low market demand for Crude) and shall not be required to produce any Well or Wells in any manner which in its sole judgment and discretion would not constitute good operating practice, nor shall Producer be obligated to drill additional Wells or to deepen, repair or rework any existing Wells.

1.4         Release Rights.

i.            Temporary Release. Notwithstanding any other provision herein, during any period after the Initial System In-Service Date, as defined in Section 2.4, when Transporter is unable or fails to accept delivery of any of Producer's Crude into Transporter's Crude System or provide alternative trucking transportation for Producer's Crude, in accordance with the terms of this Agreement for any reason whatsoever, including, without limitation, curtailment, Force Majeure or maintenance affecting Transporter's Crude System or any downstream pipeline or transporter, and there exists no uncured material breach of this Agreement on the part of Producer, then Producer may temporarily elect to deliver the Barrels of Producer's Crude which Transporter has failed to or is unable to accept to alternative facilities or transporters, or to provide its own trucking services, upon delivering written notice to Transporter of its intent to do so (a "Temporary Release "). Failure of Transporter to respond (or accept delivery of the excess Barrels of Producer's Crude) within twenty-four (24) hours to waiver request from Producer shall be deemed to be a confirmation by Transporter of lack of capacity on Transporter's Crude System. The Temporary Release of Producer's Crude shall only apply to those certain Barrels of Producer's Crude which Transporter is unable to so accept (the "Released Barrels "). Furthermore, during any Accounting Period in which a Temporary Release occurs, the applicable Minimum Barrels for such Accounting Period shall be reduced by an amount equal to the total of Released Barrels for such Accounting Period. Within thirty (30) days after Transporter's delivery of written notice to Producer of its ability to again accept delivery of the Released Barrels in whole or in part, the Temporary Release will terminate as to the quantity Transporter has specified in its written notice that it is able to receive and Producer shall resume delivery of such Released Barrels to Transporter.

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ii.           Permanent Release. Except for the six (6) month period commencing as of the Initial System In-Service Date, and subject to Section 2.5 in the context of future expansion beyond the Initial System, as applicable, in the event Transporter has not accepted delivery of the entire quantity of Producer's Crude made available by Producer at the Receipt Points for any reason whatsoever, including, without limitation, curtailment, Force Majeure or maintenance affecting Transporter's Crude System or any downstream pipeline or transporter, for a continuous period of ninety (90) consecutive days, or one hundred and twenty (120) days within a one hundred eighty (180) day period, Producer shall have the right to have the Leases and Wells affected thereby permanently released from this Agreement (a "Permanent Release") by delivering written notice thereof to Transporter within thirty (30) days after the expiration of any such ninety (90) consecutive day period or one hundred eighty (180) day period, as applicable. Furthermore, the applicable Minimum Barrels for each Accounting Period remaining during the Commitment Period shall be reduced by the Barrels produced from the Leases and Wells subject to Permanent Release for each such Accounting Period, in accordance with estimates of anticipated barrels previously provided by Producer pursuant to Section 2.7 that would have been delivered to Transporter's Crude System had the Permanent Release not occurred (the "Permanently Released Barrels").

1.5         Disposition Other than Delivery to Transporter. In consideration for the undertakings of Transporter under this Agreement, in the event that Producer, for any reason other than a failure of Transporter to accept delivery of any of Producer's Crude in accordance with this Agreement, transports for further disposition any of Producer's Crude by any means other than by delivery to Transporter, Producer shall promptly provide accurate records of such transport to Transporter. Producer shall be charged and shall pay the applicable Crude Transportation Fees to Transporter as though such Crude was delivered to Transporter at the Receipt Points for transportation on Transporter's Crude System (as such terms are defined herein) plus fifteen percent (15%). Upon Transporter's receipt of Producer's payment in full for such Barrels, such Barrels shall be deemed to be "Delivered Barrels" for purposes of calculation of the Shortfall Payment described in Exhibit "E". For the avoidance of doubt, this Section 1.5 shall not apply to Released Barrels or Permanently Released Barrels.

1.6         Memorandum of Agreement. Upon execution of this Agreement, the Parties shall concurrently execute a new Memorandum of this Agreement, in substantially the same form attached as Exhibit "D" including a legal description of the Area of Dedication that corrects and replaces the Memorandum of the Original Agreement by expressly including Emerald WB LLC as a dedicating party, together with any of Producer's other Affiliates which own or control leasehold interests or Crude from leasehold interests located within the Area of Dedication, during the Primary Term or Extended Term of this Agreement. Such Memorandum shall be placed of record in each county in which the Leases are located with Producer to bear all costs. In the event of any Permanent Release or termination of this Agreement, in whole or in part, the Parties shall execute appropriate instruments to be placed of record in each county in which the Leases are located, providing notice of the amended Area of Dedication or termination of this Agreement.

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1.7         Crude Purchaser. It is understood that Producer may enter into arrangements with purchasers of Crude Oil under which Producer's Crude may be sold to the purchaser ("Crude Purchaser" whether one or more) at or near the well pads and prior to delivery to Transporter, or downstream of the Delivery Points. If such arrangements are entered into by Producer, Producer will require the Crude Purchaser to deliver all of Producer's Crude to Transporter under the terms of this Agreement and, subject to the terms and provisions hereof, all of Producer's Crude shall remain dedicated and committed to this Agreement and subject to all provisions contained in this Agreement and Producer shall cause the Crude Purchaser to execute an adoption and ratification of this Agreement in a form and substance reasonably acceptable to Transporter.

1.8         Further Arrangements. Producer commits that, during the term of this Agreement, it will maintain, or cause its Crude Purchaser, if applicable, to maintain all necessary arrangements to provide for the further shipment or disposition of Producer's Crude at the Delivery Points. Transporter will use reasonable efforts to enter into interconnect agreements at the Delivery Points with third party pipelines and/or rail loading facilities to facilitate the further shipment or disposition of Producer's Crude. Further, Producer agrees that any connection fees, transfer fees, throughput fees or similar charges to flow Producer's Crude into a third party facility at the Delivery Points shall be borne by Producer.

1.9         Other Owner Crude. It is expressly agreed by the Parties that, except as specifically provided herein, Producer does not dedicate to the performance of this Agreement any Crude Oil attributable to the interests of other non-Affiliate working interest owners, non-Affiliate overriding royalty owners or royalty owners ("Other Owners") in the Wells or Leases operated by Producer within the Area of Dedication. However, in the event Other Owners fail to take their shares of production in kind from time to time, and such shares of production are not subject to prior dedications to third party gatherers, and Producer elects to arrange for the temporary disposition of the shares of production of such Other Owners, then the Crude attributable to such shares of Other Owners ("Other Owner Crude") shall be deemed to be "Producer's Crude"; provided, however, that such Other Owner Crude shall not thereby become dedicated to this Agreement and shall not be entitled to receive the highest priority of service afforded Producer's Crude pursuant to Section 3.5 except as required by law or applicable tariff without ratification or other formal agreement by the Other Owners, and such Other Owners shall retain their right and obligation to take their share of production in kind. To the extent Producer tenders Other Owner Crude, Producer represents and warrants to Transporter, its successors and assigns, that Producer has the right to deliver for gathering to Transporter the allocated share of Other Owner Crude tendered by Producer and indemnifies Transporter accordingly.

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ARTICLE II

FACILITIES

2.1         Transporter's Crude System. Transporter will construct, operate and maintain a Crude Oil gathering system comprised of the Initial System, and any Future Receipt Points, Future Delivery Points and expansions of Transporter's Crude System constructed pursuant to Section 2.5 (collectively "Transporter's Crude System") located as necessary to enable Transporter to receive and transport Producer's Crude from the Area of Dedication at the Receipt Points and redeliver equivalent Barrels of Crude, less Pipeline Loss Allowance and Crude provided as line fill, as defined herein, to Producer or Producer's designee at the Delivery Points. Transporter shall construct and operate the Transporter's Crude System in a workman-like manner and in accordance with good oilfield practices and in compliance with any applicable permits and licenses and all applicable rules, laws and regulations. Transporter 's Crude System will consist of:

i.           "Pipelines" mean various gathering or transportation pipelines from the Receipt Points to the Delivery Points, together with appurtenances thereto, with sufficient capacity across Transporter's Crude System, to receive, transport and redeliver Producer's Capacity, as defined in Section 3.1, attributable to such Receipt Point (as defined immediately below).

ii.           "Receipt Points" shall mean the facilities needed to connect Producer's facilities located at the locations described on Exhibit "B" as RPI through RP8 (the "Initial Receipt Points") and as RP10 through RP14 and RP16 (the "Infill Receipt Points") together with any additional locations installed as part of any expansion of Transporter's Crude System beyond the Initial System (the "Future Receipt Points"). The "Custody Transfer Point" shall be the same point as the "Receipt Point", which for both shall be the connection with Transporter's Crude System, the first flange downstream of the lease automatic custody transfer facilities ("LACTs") assembly.

m.         "Delivery Points" include the following facilities for the purpose of redelivery of Crude to Producer or its Crude Purchaser or other designee at locations described on Exhibit "B" (the "Initial Delivery Points") together with any additional locations installed as part of any expansion of Transporter's Crude System (the "Future Delivery Points "):

a.           Sufficient storage capacity to provide for proper operation of Transporter's System.

b.           Pump facilities, as necessary, to transfer Producer's Crude from the storage facilities to the Delivery Points (as described below in Section 2.3 and on Exhibit "B"), with custody transfer metering provided by the interconnecting parties. The Barrels of Producer's Crude delivered at the Delivery Points shall be based on the measurements provided by the interconnecting parties' metering.

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c.           Transporter will use its commercially reasonable efforts, and Producer will support and assist Transporter, to obtain physical Delivery Point Interconnections with downstream third party facilities. Producer shall bear its pro rata share of all Actual Construct Costs of interconnection of Transporter's Crude System with third party facilities with the interconnection to be owned and operated by Transporter. Transporter shall furnish, own and operate all Delivery Point meters if such meters are not furnished, owned and operated by third party operators of downstream interconnecting third party facilities.

iv.          Transporter's Initial System will also include actual line fill supplied by Producer to Transporter, at no cost or expense to Transporter, during the month of injection of the Crude for line fill from the Wells connected to Transporter's Crude System. For the avoidance of doubt, line fill shall be considered to be Delivered Barrels. To the extent that Transporter provides transportation services on any part of Transporter's Crude System to a party other than Producer, Producer's Crude Purchaser, or other designee, Transporter shall require the third party or Producer, as applicable, to provide its pro rata share of additional line fill (and credit Producer accordingly) for the portion of Transporter's Crude System used by that party.

v.           The portion of Transporter's Crude System that consists of the Initial System, as described below, will be designed and constructed to be capable of handling the Crude Barrels existing and anticipated from the Initial System DSUs defined herein.

2.2         Rights-of-Way. At the time of executing this Agreement, Producer has completed its acquisition of rights-of-way (the "ROW' or "ROWs") from certain landowners within the Area of Dedication ("Landowners") authorizing the construction, installation and operation of multiple pipelines within the same right-of-way corridor. Producer shall be able to assign the ROWs in part to Transporter, so as to grant Transporter the right to install a single crude gathering line and related facilities in the corridor of the ROW in connection with the construction, installation and operation of the Initial System. Due to Producer's existing relationship with the Landowners and in an effort to maximize efficiency, Producer will continue to interface directly with the Landowners until such time as the ROWs have been partially assigned to Transporter, except as described below. Producer has tendered compensation to the respective Landowner and has recorded the respective ROW with the McKenzie County Clerk and Recorder. With respect to each ROW, until such time as Producer assigns the ROWs to Transporter, Producer shall indemnify and hold harmless Transporter, its Affiliates, and their respective employees, officers, directors, contractors and subcontractors (collectively, "Transporter Indemnified Parties") from and against any and all trespass claims or claims arising out of the invalidity of any ROW brought by third party landowners arising from Transporter' s ingress to, egress from, entry upon, and use of such ROWs for survey, construction, installation and operation of the Transporter's Crude System except to the extent arising from the gross negligence or willful misconduct of Transporter Indemnified Parties.

Producer shall use commercially reasonable efforts to obtain any third party consents required to assign its ROWs to Transporter (each a "Consent to Assign"). In the event Producer, despite commercially reasonable efforts, is unable to obtain any Consent to Assign, Producer shall continue to hold such ROW for the benefit of Transporter until such time as the Consent to Assign is obtained. Concurrently with the execution of this Agreement, Producer shall partially assign the ROWs to Transporter, pursuant to the form of assignment attached hereto as Exhibit "G", and within thirty (30) days of receipt of detailed invoice and reasonably requested supporting documentation, Transporter shall pay Producer twenty percent (20%) of the actual and direct costs incurred in obtaining the ROWs (based on five (5) pipelines allowed within a ROW and adjusted up or down for fewer or more pipelines properly located within a single ROW).

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However, if Transporter determines that any ROW is unnecessary for the Initial System, or is insufficient, lacking, or otherwise defective, such that Transporter in its reasonable discretion must acquire a new right-of-way in lieu thereof, such ROW shall not be assigned to Transporter and Transporter shall not pay any portion of the costs associated with such ROW.

Transporter may proceed to interface with and acquire the real property interests it requires, including additional rights-of-way or amendments to ROWs to serve the Infill Receipt Points directly from the Landowners or other owners of such interests ("Transporter ROWs"). In the event that Transporter, despite commercially reasonable efforts, is unable to obtain any right-of-way deemed necessary for Transporter in its reasonable discretion to construct and install the portions of the Initial System serving the Infill Receipt Points prior to May 31, 2015 (an "Outstanding ROW"), Transporter may proceed with re-routing the course of the affected portion of the Initial System and acquire additional Transporter ROWs to circumvent any uncooperative third party landowners with Transporter to bear such Outstanding ROW costs and re-routing costs in the aggregate up to Eighty-Three Thousand Three Hundred and Thirty Three dollars ($83,333), which costs shall not be included in the Actual Construct Costs. In the event the Outstanding ROW costs are anticipated to exceed $83,333 the Parties shall promptly meet to develop a mutually agreeable plan to complete acquisition of Outstanding ROW. The Initial System Target In-Service Date shall be extended, as an Excused Delay as defined in Section 2.4 below, by the number of days, if any, that the construction and installation of the Initial System is delayed in order to acquire Outstanding ROW or agree on a course of action, or otherwise due directly to the Outstanding ROW.

2.3         Producer's Facilities and Construction. Producer, at its own expense, shall construct, equip, maintain and operate all facilities upstream of the Receipt Points necessary to enable Producer to deliver all of Producer's Crude to Transporter at the Receipt Points, including without limitation the following listed facilities together with all other facilities upstream of the Receipt Points as identified in Exhibits "B" and "B-2" necessary to enable Producer to deliver all of Producer 's Crude to Transporter at the Receipt Points, including without limitation, mechanical separation equipment. Producer shall provide the following facilities:

i.            "Well Meters " meaning the meters designated from time to time by Producer, located upstream of the LACT units, for metering Crude Oil on a Well-by-Well basis for Wells located on the Well Pad delivering to the Receipt Points LACTs. Producer shall install, own and operate the Well Meters. The Well Meters will be used for any required allocations to the individual wells as determined by Producer, but will not be used for determining the volumes of Producer's Crude delivered to Transporter. For all purposes under this Agreement, the volume of Producer's Crude delivered to Transporter will be determined by custody transfer measurement at the Receipt Points, not the Well Meters.

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ii.         "LACTs" shall mean the lease automatic custody transfer facilities to be supplied, owned and operated by Producer for Producer's Crude, with Transporter having a preferential right to purchase and operate such LACTs in the absence of Producer's continued ownership and operation;

iii.          rerun piping from the outlet of each Receipt Point and as otherwise needed to Producer's tankage for the return of rejected Crude Oil;

iv.         all pumps and other facilities upstream of the Receipt Points necessary to enable Producer to deliver all of Producer's Crude to the Receipt Points and able to provide a pressure necessary for delivery into Transporter's Crude System; and

v.           power and other utilities for Producer's facilities. Additionally, Producer will provide Transporter with power and other utilities for use by Transporter's Crude System.

2.4         Initial System. The "Initial System" will consist of the initial facilities of Transporter, described generally above and on Exhibit "B", as necessary to connect the Initial Receipt Points and Infill Receipt Points with the Initial Delivery Points, also described on Exhibit "B". The Parties have agreed upon the configuration, design and construction of Transporter's Crude System and have deemed the Initial System as sufficient to serve all of Producer's Minimum Barrels commitment stated in Exhibit "E", and that the Initial System is sufficient to serve all of Producer's anticipated Barrels of Producer's Crude from the Wells identified on Exhibit "B-2" (collectively , the "Initial System Wells") at the Initial Receipt Point or Infill Receipt Point listed in the column "Transporter Receipt Point Construction Responsibilities" next to each such Well.

Subject to events of Force Majeure, severe winter weather, frost laws, road restrictions and other requirements or delays imposed by government agencies including without limitation delays in issuing ROWs on federal lands needed for the portion of Transporter's Crude System serving the Infill Receipt Points, whether or not within the scope of Force Majeure, that would make the diligent pursuit of similar construction or installation operations unreasonable for a reasonably prudent McKenzie County North Dakota gatherer faced with similar conditions (whether one or more, "Excused Delays"), Transporter shall diligently construct, install and complete (y) the portion of Transporter's Crude System serving the Initial Receipt Points as described on Exhibit "B" and Exhibit "B-2" on or before June 1, 2015 (the "Start-Up Target Date"), and (z) all of the Initial System including the Initial and Infill Receipt Points, on or before August 31, 2015, as extended by the number of Days equal to any Excused Delay event (the "Initial System Target In-Service Date ") . The Parties each agree that their respective obligations to meet the Start-Up Target Date are on a reasonable commercial efforts basis with no credits or penalties applicable to either Party for non-achievement. Producer acknowledges and agrees that any receipt, gathering and delivery of Crude by Producer prior to the Initial System In-Service Date shall incur the applicable Crude Delivery Fees and shall be provided on an interruptible basis at Transporter's sole discretion as Transporter may be completing the installation and construction of its Crude System and may also need to undertake calibration and other activities to achieve the Initial System In-Service Date during that period, provided however, that Transporter shall notify Producer 24 hours or as soon as practicable prior to any activities of Transporter that may reasonably be expected to cause an interruption or otherwise prevent Transporter from receiving Crude from any Receipt Point from which Transporter has previously accepted Crude, and Transporter shall keep Producer fully informed of the progress of such activities and any anticipated resumption of service from such Receipt Point(s). The date on which Transporter has completed the construction and installation of the Initial System, in its entirety so as to be capable of receiving Producer's Crude from all of the Initial Receipt Points and Infill Receipt Points identified on Exhibits "B" and "B-2", shall be the "Initial System In-Service Date". For avoidance of doubt, such completion by Transporter shall be a deemed achievement of the Initial System In-Service Date notwithstanding the Initial System's partial or complete inability to accept and flow Crude on the Initial System when such inability arises solely from Producer's delay or failure to complete its responsibilities and obligations under this Agreement, as extended by Force Majeure or in the case of delay or failure to complete re-run piping if caused by frost laws imposed by government agencies.

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i.            In the event, subject to Force Majeure or Excused Delay, Transporter fails to complete its construction of the Initial System, in its entirety per Section 2.4, Exhibit "B" and Exhibit "B-2", on or before the Initial System Target In-Service Date, and Producer has completed all facilities upstream of the Initial and Infill Receipt Points per Section 2.3, Exhibit "B" and Exhibit "B-2", and is otherwise ready, willing and able to deliver Producer's Crude to that portion of the Initial System that is not completed, the following shall occur:

a.           the applicable Minimum Barrels for each Accounting Period, or portion thereof, between the Initial System Target In-Service Date and the Initial System In-Service Date, shall be reduced by the Barrels of Producer's Crude produced from the Initial System In-Service Date Wells that would have been transported on the Initial System had such System been in operation for each such Accounting Period (the "Transporter's Initial System Delay Barrels "); and

b.           In lieu of Producer receiving a credit against the Crude Transportation Fees owed by Producer, Producer may assess a per diem penalty against Transporter for each day of delay with the per diem penalty amount equal to Twenty-One cents ($0.21) per Barrel for the Transporter's Delay Barrels ("Initial System Transporter Delay Fee") up to a maximum total payment of Two Million dollars ($2,000,000) in the aggregate for all Transporter's Initial System Delay Penalty under this Agreement together with all "Transporter's [or Gatherer's] Initial System Delay Pre-Inservice Barrels [or Volumes]" as defined under the Related Dedication Agreements described in Section 8.3 herein as the "Initial System Pre-Inservice Credit”. The Parties acknowledge and agree that any Initial System Transporter Delay Fee arises wholly from construction delays of Transporter, and is unrelated to transportation services provided by Transporter under its Tariff. In the event this limitation on payment to Producer is inconsistent with any FERC requirements, the Parties agree to pursue a mutually fair and equitable solution.

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ii.           In the event Transporter has completed its construction of the Initial System, in its entirety per Section 2.4, Exhibit "B" and Exhibit "B-2", on or before the Initial System Target In-Service Date, but, subject to Force Majeure or in the case of delay or failure to complete re-run piping if caused by frost laws imposed by government agencies, Producer has failed to complete all facilities upstream of the Initial and Infill Receipt Points per Section 2.3, Exhibit "B" and Exhibit "B-2", and Transporter is otherwise ready, willing and able to receive and gather Producer's Crude on that portion of the Initial System, then the following shall occur:

a.           the applicable Minimum Barrels for each Accounting Period, or portion thereof, between the Initial System Target In-Service Date and the Initial System In-Service Date, shall be reduced by the Barrels of Producer's Crude produced from the Initial System In-Service Date Wells that would have been transported on the Initial System had Producer's Crude Facilities been in operation for each such Accounting Period (the "Producer's Initial System Delay Barrels ").

b.           Producer shall pay Transporter an amount equal to Twenty-One cents ($0.21) per Barrel for the Producer's Initial System Delay Barrels ("Initial System Producer Delay Fee") beginning in the first Accounting Period following the Initial System In-Service Date and continuing for each successive Accounting Period until the payment is satisfied in full, up to a maximum total payment of Two Million dollars ($2,000,000) for all Producer 's Initial System Delay Barrels under this Agreement together with all "Producer's Initial System Delay Pre-Inservice Barrels [or Volumes]" as defined under the Related Dedication Agreements described in Section 8.3 herein ("Initial System Pre-Inservice Fee "). The Parties acknowledge and agree that any Initial System Producer Delay Fee arises wholly from construction delays of Producer, and is unrelated to transportation services provided by Transporter under its Tariff. In the event this limitation on payment by Producer is inconsistent with any FERC requirements, the Parties agree to pursue a mutually fair and equitable solution.

iii.          In addition to Producer's remedies under Section 2.4(i), in the event Transporter fails to complete its construction of the Initial System, in its entirety per Section 2.4, Exhibit "B" and Exhibit "B-2", on or before the date that is sixty (60) Days after the Initial System Target In-Service Date, and Producer has completed all facilities upstream of the Initial and Infill Receipt Points per Section 2.3, Exhibit "B" and Exhibit "B-2" and is otherwise ready, willing and able to deliver Producer's Crude to that portion of the Initial System that is not completed, Producer shall have the option, exercisable in its sole discretion, to elect by written notice to Transporter to construct and install the remainder of the Initial System, at Producer's sole cost and expense, whereupon Producer shall not owe any Crude Transportation Fees for any Crude delivered to the Initial and Infill Receipt Points or flowing through that portion of the Initial System constructed and installed by Producer, until such time as the amount of Crude Transportation Fees otherwise attributable to such Crude, but retained by Producer, is equal to one hundred and ten percent (110%) of the total of Actual Construct Costs incurred by Producer to complete the construction and installation of the remainder of the Initial System.

iv.         Transporter shall keep Producer reasonably informed of the progress on the construction and installation of the Initial System, and any Excused Delays in connection therewith. Producer shall have the right to have its representative present during any onsite construction or installation operations of the Initial System.

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2.5         Future Expansion Beyond the Initial System. After installation of the Initial System, Transporter will install and connect such Future Receipt Points, Future Delivery Points, and expansions of Transporter's Crude System, including but not limited to, installing additional or "looped" gathering lines or a larger diameter pipe that Transporter in its sole judgment determines are necessary or desirable to gather or transport Producer's Crude dedicated under this Agreement from subsequent completed Wells drilled or acquired by Producer within the Area of Dedication as set forth in this Section 2.5. For avoidance of doubt, any expansion of Transporter's Crude System to serve Producer's Wells located outside of the Area of Dedication is not contemplated by or covered under the scope of this Agreement. The Parties agree that Transporter will own and operate any and all future expansions to Transporter's Crude System including any Producer Built Transportation Facility, as defined in Section 2.6 herein.

i.            In addition to providing Transporter with annual drilling plans and quarterly updates to those plans under Section 2.7 below, Producer shall give Transporter written notice (a "Connection Notice" ) one hundred twenty (120) to ninety (90) Days prior to the completion of any new Well located within the Area of Dedication but outside of the Initial System DSUs, or within ten (10) days after acquiring any such completed Well, specifying: the Well name; Well location; the location of the nearest Receipt Point or proposed Future Receipt Point, as applicable, for such Well; drilling, completions and anticipated recompletion details; the minimum anticipated initial and annual Barrels of Producer's Crude from such Well together with the anticipated available Barrels of Producer's Crude and Other Owner Crude from the drilling spacing unit ("DSU') in which the Well is located as may be requested by Transporter; and if a Distant Expansion under subsection (iv) below applies, also specifying up to four (4) DSUs that are each directly adjacent to or cornering the DSU (the "Contiguous DSUs") of the Distant Well (defined below) for possible Permanent Release at Producer 's sole discretion under subsection (iv)(a) below if (iv)(a) applies and the anticipated available volumes of Producer's Crude from the four (4) Contiguous DSUs as may be requested by Transporter (the anticipated volumes from the DSU of the Distant Well and the four (4) Contiguous DSU Barrels if requested, are collectively the "Connection Barrels"). Concurrently with its Connection Notice under this Agreement, Producer shall provide Transporter with "Connection Notices" concerning the Well as required under the Related Dedication Agreements described in Section 8.3 of this Agreement. If a Well that is the subject of a Connection Notice is not completed within one hundred twenty (120) days of the Connection Notice, following good faith discussions with Producer, Transporter shall then have the option to deem the Connection Notice as invalid and of no further effect.

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ii.           In the event the Well, or the Future Receipt Point, if applicable, as identified in the Connection Notice requires less than or equal to a three (3) mile expansion of Transporter's Crude System from an existing Receipt Point or Delivery Point, as Transporter's Crude System exists as of the date of the Connection Notice (a "Nearby Well"), Transporter shall have the first option to construct, install and place into operation an expansion of Transporter's Crude System to connect to the Nearby Well at Transporter's sole cost and expense, in exchange for Transporter's ability to charge Producer an additional fee per Barrel for any Crude from such Nearby Well or any other Well Producer flows through such expansion constructed by Transporter based on the sample calculation set forth in Exhibit "H," such that Transporter has recouped its Actual Construct Costs incurred by Transporter to construct the expansion plus incremental operating expenses and capital expenditures, including capital expenditures needed to modify or upsize the Initial System or a prior expansion of the Initial System to accommodate the Connection Volumes, over a five (5) year period and receive a seven and a half percent (7.5%) internal rate of return ("IRR" as calculated by the Microsoft Excel IRR function financial formula) and trued up quarterly ("Expansion Fee" ) . For the avoidance of doubt the Expansion Fee shall be in addition to all other Crude Transportation Fees due for the Connection Volumes and such Expansion Fee shall be reduced equitably if Transporter, in its sole discretion, elects to construct and install an expansion of larger size or greater capacity than requested by Producer in its Connection Notice or required to serve Producer's Connection Barrels.

iii.          Subject to Force Majeure and the condition that Producer has in fact completed such a Nearby Well, in the event Transporter fails to timely construct, install and make available for operation on or before the later of ninety (90) days from receipt of the Connection Notice or the date the Well identified in the respective Connection Notice is completed, an expansion of Transporter's Crude System to connect the Connection Barrels from the Nearby Well, following good faith discussions with Transporter, Producer shall then have the option either to:

a.           Construct and install an expansion of Transporter's Crude System to connect Transporter's Crude System existing at that time to the Nearby Well, at Producer's sole cost and expense, in exchange for Producer receiving a credit against any Base Fee component of the Crude Transportation Fees otherwise owed Transporter for any Crude from such Nearby Well or any other Well flowing through such expansion constructed by Producer, until such time as the amount of the Base Fee component of the Crude Transportation Fees otherwise attributable to such Crude, but retained by Producer, is equal to the total of Actual Construct Costs incurred by Producer to construct the expansion based on the sample calculation set forth in Exhibit "H," such that Producer has recouped its Actual Construct Costs incurred by Producer to construct the expansion plus incremental operating expenses and capital expenditures, including capital expenditures needed to modify or upsize the Initial System or a prior expansion of the Initial System to accommodate the Connection Volumes, over a five (5) year period and receive a seven and a half percent (7.5%) IRR and trued up quarterly ("Expansion Credit” ); or

b.           Subject to Section 1.4(ii), obtain a Permanent Release from this Agreement of the Nearby Well and any of the Leases located within the same DSU as the Nearby Well but not located within an Initial System DSU.

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iv.         In the event the Well, or the Future Receipt Point or Delivery Point, if applicable, as identified in the Connection Notice requires more than a three (3) mile expansion of Transporter's Crude System, as Transporter's Crude System exists as of the date of the Connection Notice ("Distant Well"), or involves a connection of Transporter's Crude System with facilities of third parties not connected to Transporter's Crude System as of the date of the Connection Notice (one or both situations, a "Distant Expansion"), the Parties shall promptly pursue good faith negotiations of mutually agreeable terms and conditions of such an expansion and strive to enter into a definitive separate agreement or written amendment setting forth a definitive agreement as to such Distant Expansion. In the event the Parties have not reached agreement, on or before the later of ninety (90) days from receipt of the Connection Notice or the date the Well identified in the respective Connection Notice is completed, for the terms of such a Distant Expansion of Transporter's Crude System, following good faith discussions with Transporter, Producer shall have the option to:

a.           Subject to Section l .4(ii), obtain a Permanent Release from this Agreement of any of the Leases located within the DSU of the Distant Well and the four (4) Contiguous DSUs but only if such Leases are not located within an Initial System DSU.

v.           Transporter shall keep Producer reasonably informed of the progress on the construction and installation of any expansion of Transporter's Crude System. Producer shall have the right to have its representative present during any onsite construction or installation operations of any expansion of Transporter's Crude System.

vi.          The Parties agree that the terms and conditions of any future expansion beyond the Initial System that are not related to transportation service may be addressed in a separate facilities construction agreement between the Parties on the condition that they remain consistent with this Agreement.

2.6         Construction or Expansion by Producer. In the event Producer elects to construct, install or expand any portion of Transporter 's Crude System pursuant to an express right provided under this Agreement (a "Producer Built Transportation Facility "), the following shall apply:

i.            Each Producer Built Transportation Facility shall be constructed and installed by Producer according to the reasonable design and construction specifications of Transporter. In constructing and installing the Producer Built Transportation Facility, Producer shall have the right to utilize any available crude pipeline right-of-way or easement rights of Transporter and any materials of Transporter, at cost.

ii.           Upon completion of any Producer Built Transportation Facility, Producer shall assign such Producer Built Transportation Facility to Transporter, at no charge to Transporter, but expressly subject to the terms of this Agreement, whereupon it shall become part of Transporter's Crude System.

m.          If Producer has incurred Actual Construct Costs pursuant to Section 2.5(iii)(a), once Producer has recouped all of such Costs pursuant to Section 2.5, Transporter may begin to assess the applicable Base Fee component of Crude Transportation Fees for all Crude delivered by Producer into or flowing through such Producer Built Transportation Facility. Transporter may begin to assess all other components of the Crude Transportation Fees for all Crude delivered by Producer beginning upon the commencement of receipt into or flow through such Producer Built Transportation Facility.

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iv.         For the avoidance of doubt, for purposes of determining whether Producer has delivered the Minimum Barrels in any Accounting Period pursuant to the terms and conditions set forth on Exhibit "E", any Crude delivered during such Accounting Period for which Producer does not owe any Base Fee component of the Crude Transportation Fees pursuant to its incurrence of Actual Construct Costs pursuant to Article 2 of this Agreement shall be included in the Delivered Barrels.

2.7         Producer's Anticipated Barrels. Upon the execution of this Agreement, and thereafter by October first (1st) of each calendar year, Producer shall communicate its drilling, completion and recompletion plans to Transporter in writing, including locations, anticipated spud dates, together with anticipated Barrels to be delivered to Transporter, for the next calendar year. Additionally , during Transporter's construction of facilities to serve the Infill Receipt Points, Producer shall promptly notify Transporter of any delay in its drilling and completion schedules for the Wells identified in Exhibit "B-2'', including without limitation delays in completion of any Wells on Exhibit "B-2" later than June 1, 2015 . At all other times during the Primary Term or Extended Term, no later than the last day of each calendar quarter, Producer shall notify Transporter in writing with reasonable detail of any changes or additions to its drilling plans for the succeeding twelve (12) Accounting Periods. In addition to providing Connection Notices, pursuant to Section 2.5(i), Producer shall provide updates to Transporter, as needed, of specific drilling and completion plans, actual initial production dates, and additional volumes from Other Owner Crude or from prior dedications.

2.8         Ownership of Facilities. Producer expressly does not by the terms of this Agreement, sell, transfer or assign unto Transporter any title or interest whatsoever in the Leases or any pipelines or other equipment of any nature owned or used by Producer in the operation of Producer's Wells and the Leases. Transporter expressly does not by the terms of this Agreement, sell, transfer or assign unto Producer any title or interest whatsoever in Transporter's Crude System, or any pipelines or other equipment of any nature owned and used by Transporter in the operation of Transporter's Crude System or its performance of services under this Agreement.

ARTICLE III

TRANSPORTATION SERVICE

3.1         Producer's Capacity. Commencing on the Initial System In-Service Date and subject to the capacity allocation and apportionment provisions of Transporter's Tariff, Transporter shall make available Capacity equal to Producer's anticipated Barrels of Producer's Crude to be delivered pursuant to Sections 2.4 and 2.7 ("Producer's Capacity ") in the aggregate, for the benefit of Producer's Crude, subject to Force Majeure and the capacity of the Initial System. On a daily basis, any capacity available in the Transporter's Crude System in excess of the lesser of Producer' s Capacity or the actual amount of Producer's Crude made available for delivery by Producer to Transporter each Day hereunder, shall be available to Transporter for third party Barrels on such Days. Producer 's Capacity shall be adjusted upward by additional Connection Barrels served by expansions of Transporter's Crude System pursuant to Section 2.5 of this Agreement, and downward by Permanently Released Barrels pursuant to Section l .4(ii) of this Agreement.

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3.2         Transportation. Subject to the terms and conditions of this Agreement and subject to Transporter's Tariff, Transporter shall receive at the Receipt Points and gather Producer's Crude utilizing Transporter 's Crude System, up to Producer's Capacity, and redeliver the same quantity, quality and API gravity in Barrels of Producer's Crude less the Pipeline Loss Allowance to Producer or its designee at the Delivery Points in consideration of Producer's payment of the Crude Transportation Fees provided on Exhibit "E". In accordance with and subject to Transporter's Tariff, Transporter also agrees to receive and transport any of Producer's Crude in excess of Producer's Capacity and Other Owner Crude on an uncommitted basis and to redeliver to Producer or its designee the equivalent Barrels of Crude, less Pipeline Loss Allowance to Producer or its designee at the Delivery Points in consideration of Producer's payment of the Crude Transportation Fees provided on Exhibit "E" for such Producer's Crude and Other Owner Crude.

3.3         Uniform Delivery Rate. Producer's Crude will be delivered and redelivered on a uniform basis consistently and Producer may not vary its production or utilize portions of Transporter's Crude System ina manner designed to take advantage of market changes, obtain storage services or act as peaking service.

3.4         Third Party Crude. Producer acknowledges and understands that Transporter will receive Producer's Crude utilizing Transporter's Crude System which may also receive and commingle Producer's Crude with Third Party Crude delivered to Transporter by other parties, at all times subject to Transporter's Tariff, Producer's Capacity and such Third Party Crude meeting the Crude Oil Quality Specifications set forth in the attached Exhibit "F." Accordingly, the Crude Oil delivered to the Producer or Producer's Crude Purchaser or other designee at the Delivery Points may not be the same Crude Oil, but shall have the same quality, API gravity and other characteristics, as Producer's Crude delivered to the Receipt Points.

3.5         Priority of Service. Except for any Other Owner Crude that has not been dedicated to this Agreement by ratification or other formal agreement entered into by such Other Owners and in accordance with and subject to Transporter' s Tariff, Producer's Crude, up to Producer's Capacity, shall obtain highest priority on Transporter's Crude System with respect to capacity allocations, interruptions, or curtailments. On a Receipt Point or Delivery Point basis as applicable, in accordance with and subject to Transporter's Tariff Producer's Crude will be the last Crude curtailed from Transporter's Crude System in the event of an interruption or curtailment affecting specific Receipt Points or Delivery Points rather than Transporter's Crude System as a whole, and all of Producer's Crude affected by a particular Receipt Point or Delivery Point will be treated in the same manner in the event an allocation is necessary except as otherwise provided in Transporter's Tariff. Transporter agrees not to contract to provide, at any time, transportation service on Transporter's Crude System on a basis that has a priority higher than what Producer's Crude is entitled to pursuant to this Section 3.5 and under this Agreement, except as otherwise provided in Transporter's Tariff.

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ARTICLE IV

EXHIBITS

4.1         Exhibits. All Exhibits attached to this Agreement are incorporated into and made an integral part of this Agreement by reference including the General Terms and Conditions set forth in the attached Exhibit "C" (the "GT&C").

4.2         Order of Precedence. In the event of any conflict between the terms as set out in the body of this Agreement and those set out in the GT&C, the terms in the body of this Agreement shall control. In the event of any conflict between the terms as set out in the body of this Agreement and those set out in Transporter's Tariff, the terms in the Tariff shall control.

ARTICLE V

CONSIDERATION & FEES

5.1         Fees. Transporter shall charge and Producer shall pay the applicable "Crude Transportation Fees" and any "Shortfall Payment" described on Exhibit "E" based on the total Barrels of Crude delivered by Producer or its Crude Purchaser and received at the Receipt Points. If and as applicable under Section 2.4(ii)(b), Transporter shall charge and Producer shall pay the Initial System Pre-Inservice Fee. If and as applicable under Section 2.5, Transporter shall charge and Producer shall pay the Expansion Fee.

5.2         Annual Fee Adjustments. The Base Fee and any applicable Miscellaneous Fees including without limitation the Expansion Fee may be adjusted annually during the term of this Agreement, effective July 1 for the prospective twelve-month annual period ending June 30, the first prospective annual period beginning July 1, 2020, by multiplying the rate in effect on June 30 immediately prior to the annual period to which the adjustment shall apply by the index published by the FERC pursuant to Section 342.3(d) of the oil pipeline rate regulations of the FERC, but shall never be less than the Base Fee set forth in Exhibit "E".

5.3         Utilities. Producer shall furnish utilities needed for Transporter's Crude System at the Receipt Points. In addition to the Crude Transportation Fees and utilities furnished by Producer, Transporter shall charge and Producer shall pay its pro rata share of the actual utility costs incurred by Transporter in connection with operating its Crude Transportation System including any necessary power costs incurred in connection with the Delivery Points. The actual utility costs shall be allocated on a pro-rata basis to each shipper of Crude Oil on Transporter's Crude System each Accounting Period based upon throughput of all Crude through Transporter's Crude System during such Accounting Period, or as otherwise provided in applicable tariff.

5.4         Pipeline Loss Allowance. The difference between the Barrels of Producer's Crude as measured at the Receipt Points and the summation of the measurements provided by the interconnecting parties at the Delivery Points shall be considered as a pipeline loss allowance for all losses sustained on Transporter's Crude System due to evaporation, measurement and other losses in transit ("Pipeline Loss Allowance "). The Pipeline Loss Allowance shall be allocated on a pro-rata basis to each shipper of Crude Oil on Transporter's Crude System. Transporter shall not be responsible to Producer for the Pipeline Loss Allowance. Notwithstanding anything to the contrary herein, Producer's pro rata share of Pipeline Loss Allowance for any Accounting Period, shall not exceed one percent (1.0%) Producer's Crude delivered to Transporter's Crude System for such Accounting Period.

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ARTICLE VI

NOTICES

6.1         Notice Process. All notices and communications required or permitted under this Agreement shall be in writing and shall be considered as having been given if delivered personally, or when received by mail, by electronic means (confirmed as received before 5 p.m. at the place of receipt), or by express courier, postage prepaid, by either Party to the other at the addresses given below. Routine communications, including monthly statements, shall be considered as duly delivered when mailed by ordinary mail or by electronic means.

6.2         Addresses for Notice. Unless changed upon written notice by either Party, the addresses for notice purposes are as follows:

TO: Emerald Oil, Inc. and/or Emerald WB LLC

1600 Broadway, Suite 1360

Denver, CO 80202

Phone: 303-595-5629

Contact: James Muchmore

TO: Dakota Midstream, LLC or Dakota Energy Connection, LLC

1600 Broadway, Suite 1330

Denver, CO 80202

Phone: 202-213-5998

Contact: Tim Reynolds

ARTICLE VII

TERM

7.1         Primary and Extended Terms. This Agreement shall commence as of the Effective Date and shall remain in full force and effect for a primary term of fifteen (15) years (the "Primary Term ") and shall continue year to year thereafter until terminated by either Party (the "Extended Term") by providing written notice of termination to the other Party at least sixty (60) days prior to the expiration of the Primary Term or any subsequent annual expiration date.

7.2         Capacity Adjustment. During any Extended Term, Producer's Capacity will be the average daily Barrels of Producer's Crude delivered to Transporter's Crude System during the prior twelve (12) month period.

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7.3         Uneconomic Operations. Subject to any Force Majeure event affecting Producer's obligations to deliver Crude hereunder, in addition to all other rights of Transporter under this Agreement, in the event the sum of actual direct costs (for the avoidance of doubt, excluding overhead, depreciation, amortization and capital expenditures) incurred by Transporter to operate any portion of Transporter's Crude System (the "Uneconomic Segment")during any ninety (90) day period are in excess of the total net revenue attributable to the Uneconomic Segment (including all Crude Transportation Fees paid by Producer or any third party attributable to the Uneconomic Segment) during such ninety (90) day period, Transporter shall have the right to send written notice (an "Uneconomic Notice ") to Producer of its intent to terminate receipts of Crude into the Uneconomic Segment unless the Crude Transportation Fees owed by Producer for Producer's Crude delivered to the Uneconomic Segment are increased such that Transporter's total anticipated net revenue attributable to the Uneconomic Segment is projected to equal one hundred ten percent (110%) of Transporter's actual direct costs (for the avoidance of doubt, excluding overhead, depreciation, amortization and capital expenditures) incurred by Transporter to operate the Uneconomic Segment. Any increased Crude Transportation Fee shall be borne pro-rata by Producer and any third party shipper on the Uneconomic Segment according to the anticipated Barrels of Producer's Crude and Third Party Barrels to be delivered to or flowed through the Uneconomic Segment. Within ten (10) days of Producer's receipt of notice from Transporter, Producer shall elect by written notice sent to Transporter either to:

1.          Accept the increased Crude Transportation Fees, or portion thereof, effective as of the beginning of the next Accounting Period, owed by Producer for Producer's Crude delivered to the Uneconomic Segment, whereupon Transporter shall not send another Uneconomic Notice pursuant to this Section 7.3 for at least ninety (90) days; or

ii.          Obtain a Temporary Release of the Leases and Wells directly affected by the Uneconomic Segment, with Producer able to elect, by delivery of written notice to Transporter, to obtain a Permanent Release and terminate the Agreement, insofar as it pertains to the Uneconomic Segment after one hundred eighty (180) days of Producer's receiptof the Uneconomic Notice under this Section 7.3.

ARTICLE VIII

MISCELLANEOUS

8.1         Assignment. This Agreement, including, without limitation, any and all renewals, extensions, amendments and/or supplements hereto shall extend to and inure to the benefit of and be binding upon the Parties, and their respective successors and assigns, including any purchaser of Producer's Crude or Producer 's interests in the Leases that are dedicated under this Agreement or subsequent operator of the Wells, and any purchaser of Transporter' s Crude System, or any part or interest therein which are subject to this Agreement; provided, however, (i) this Agreement shall not be assigned by a Party without the prior written consent of the other Party, such consent not to be unreasonably withheld, conditioned or delayed, and (ii) no sale, assignment, conveyance or other transfer (collectively, a "Transfer") of Producer' s Leases or Wells, or any part thereof or interest therein, or any part of Transporter 's Crude System, shall be made unless the transferee thereof shall assume and agree to be bound by this Agreement insofar as the same shall affect and relate to the Leases, Wells, Transporter's Crude System or interests so Transferred. Notwithstanding the conditions and restrictions set forth on assignment in this Section 8.1, each Party retains the right to freely assign this Agreement to an Affiliate within the first year following the Effective Date. Interests owned in the Area of Dedication by a transferee of any of Producer's Leases or Wells that were owned prior to the effective date of such Transfer shall not become subject to this Agreement by virtue of such Transfer. It is further agreed, however, that nothing herein contained shall in any way prevent a Party from pledging or mortgaging, all or any part of such Producer's Leases if Producer, or Transporter's Crude System if Transporter, as security under any mortgage, deed of trust, or other similar lien, or from pledging this Agreement or any benefits accruing hereunder to the Party making the pledge without the assumption of obligations hereunder by the mortgagee, pledgee or other grantee under such instrument.

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8.2         No Third Party Beneficiaries. Nothing in this Agreement, expressed or implied, confers any rights or remedies on any person or entity not a party hereto other than successors and assigns of the Parties.

8.3         Cooperation Under Related Dedication Agreements. The Parties expressly acknowledge that this Agreement is one of several agreements executed contemporaneously herewith by Producer, Transporter, or an Affiliate of Transporter pertaining to the gathering or transportation of Gas and water, and the disposal of water from the same Leases and Wells and covering the same Area of Dedication (the "Related Dedication Agreements"), with certain facilities to be located, and services to be provided, under this Agreement in proximity to those covered under the Related Dedication Agreements. The cooperation and performance by the Parties and their respective Affiliates of all of the obligations under this Agreement and each of the Related Dedication Agreements is essential for the Parties to receive the full benefit of their bargain under this Agreement and the Related Dedication Agreements. Subject to Force Majeure and any other applicable provisions under this Agreement or any Related Dedication Agreement, Transporter and each Affiliate of Transporter which is a party to a Related Dedication Agreement, shall construct, install and put into service the Initial System, pursuant to this Agreement, and the corresponding Initial Systems for Gas gathering and water gathering as described in the Related Dedication Agreements, in each case, in their entirety, as to all of the Initial and Infill Receipt Points together with any future expansions beyond the Initial System undertaken pursuant to this Agreement and under the corresponding provisions of the Related Dedication Agreements.

8.4         Entirety; Amendment. Subject to Section 8.3, this Agreement together with the Exhibits attached hereto, constitutes the entire agreement and understanding between the Parties hereto and supersedes and renders null and void and of no further force and effect any prior proposals, understandings, negotiations or agreements between the Parties relating to the subject matter hereof, and all amendments and letter agreements in any way relating thereto. No provision of this Agreement may be changed, modified, waived or discharged orally, and no change, modification, waiver or amendment of any provision will be effective except by written instrument executed by the Parties.

8.5         Severability. Should any part of this Agreement be found to be void, unenforceable or be required to be modified by a court or governmental authority, then only that part of this Agreement shall be voided, unenforceable, or modified accordingly. The remainder of this Agreement shall remain in force and unmodified, subject to Section 6 of the GT&C.

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8.6         Additional Crude Services; Area of Interest. In the event Producer desires to construct, install, operate or perform other LACT operation and measurement other than as set forth in this Agreement, Crude conditioning or other Crude field services or Producer desires crude transportation services in areas of McKenzie County south of Township 150, Billings County, or Stark County, North Dakota ("Area of Interest”) (such additional types of locations or desired services collectively "Additional Crude Services"), Producer shall give notice to Transporter regarding such Additional Crude Services before soliciting such Additional Crude Services or entering into any binding agreements with any third parties to perform such Additional Crude Services. The selection of Transporter or any third party to perform such Additional Crude Services shall be in the sole discretion of Producer, and the performance of such Additional Crude Services shall be at governed by a separate agreement containing mutually agreeable terms and conditions.

8.7         Audit Rights.

i.            Except for Actual Construct Costs for which a process of disclosure and agreement is provided within Section 1(b) of the GT&C and Initial System Costs which are further addressed in Exhibit "E", upon ten (10) days prior written notice, either Party shall have the right, at reasonable times during normal business hours, but no more frequently than once each calendar year, at its own expense, to examine the books and records of the other Party to the extent necessary to audit and verify the accuracy of any statement, charge, or computation made under or pursuant to this Agreement. All statements, allocations, measurement, and payments made in any Accounting Period prior to the twenty-four (24) Month period preceding the Month in which notice of audit is given by the auditing Party shall be conclusively deemed to be true and correct and the scope of such audit shall be limited to statements, allocations, measurements and payments made during such twenty-four (24) Month period.

11.         The auditing Party shall have ninety (90) days after commencement of the audit in which to submit a written claim, with supporting detail, for proposed adjustments. If the auditing Party fails to submit a written report to the audited Party within the ninety (90) day period, then all statements, charges and computations made under or pursuant to this Agreement that were within the audit period shall be deemed to be appropriate and accurate. Upon receipt of an audit report, the audited Party shall have ninety (90) days to make all recommended adjustments, or to notify the auditing Party that it does not agree and its basis for disagreement. Any unresolved disagreements shall be resolved pursuant to Section 10 of the GT&C.

8.8        Amendment and Restatement of Original Agreement.

i.            Upon execution of this Agreement by Transporter and Producer, this Agreement shall amend, restate, supersede and replace the Original Agreement, including any amendments thereto, in its entirety and for all purposes, effective as of the Effective Date.

ii.           Notwithstanding anything to the contrary herein, the provisions of the Original Agreement relating to transportation services shall remain effective with respect to transportation services provided by Transporter for Producer under the terms of the Original Tariff until such time as amendments to Transporter's Tariff have been filed and become effective to implement the additional Receipt Points, revised rates, and other conforming Tariff revisions required to implement the amended provisions of this Agreement. Thereafter, the provisions of this Agreement relating to transportation services provided by Transporter under the terms of its amended Tariff shall become effective prospectively for all purposes.

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8.9         Governing Law; Venue. THIS AGREEMENT SHALL BE CONSTRUED IN ACCORDANCE WITH AND GOVERNED BY THE LAWS OF THE STATE OF NORTH DAKOTA WITHOUT REGARD TO PRINCIPLES OF CONFLICTS OF LAWS. EXCLUSIVE VENUE FOR ANY SUIT, ACTION OR PROCEEDING BROUGHT BY EITHER PARTY IN CONNECTION WITH THIS AGREEMENT OR ARISING OUT OF THE EFFECTIVE TERMS OR CONDITIONS HEREOF SHALL BE IN THE CITY AND COUNTY OF DENVER, COLORADO.

8.10       Counterparts. This Agreement may be executed in multiple counterparts, each of which shall constitute an original and all of which, when construed together, shall constitute one and the same instrument.

8.11       Ratification. Emerald WB LLC hereby ratifies, confirms and approves the Agreement in all respects and adopts it as Emerald WB LLC's act and deed to the same extent as if the Agreement had been executed by Emerald WB LLC on the date of its original execution, effective as of the Effective Date.

[Signature Page Follows]

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THE PARTIES HERETO have executed this Agreement effective as of the Day and year first above written.

TRANSPORTER		PRODUCER
DAKOTA MIDSTREAM LLC		EMERALD OIL, INC.
By:	/s/ Tim Reynolds	By:	/s/ McAndrew Rudisill
Name:	Tim Reynolds	Name:	McAndrew Rudisill
Title:	Founding Partner	Title:	Chief Executive Officer and President
Date:	5/26/15	Date:	5/26/15
DAKOTA ENERGY CONNECTION, LLC		EMERALD WB LLC
By:	/s/ Tim Reynolds	By:	/s/ McAndrew Rudisill
Name:	Tim Reynolds	Name:	McAndrew Rudisill
Title:	Founding Partner	Title:	Chief Executive Officer and President
Date:	5/26/15	Date:	5/26/15

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EX-10.5

Exhibit 10.5

AMENDED AND RESTATED GAS DEDICATION AND GATHERING AGREEMENT
BETWEEN
DAKOTA MIDSTREAM, LLC
AND
EMERALD OIL, INC. & EMERALD WB LLC

AMENDED AND RESTATED GAS DEDICATION
AND GATHERING AGREEMENT

THIS AMENDED AND RESTATED GAS DEDICATION AND GATHERING AGREEMENT ("Agreement') is entered into on May 26, 2015, but effective as of the 1st day of July, 2014 (the "Effective Date" ) by and between DAKOTA MIDSTREAM, LLC ( "Gatherer"), and EMERALD OIL, INC. and EMERALD WB LLC (collectively "Producer"). The term "Producer" shall also include any other Affiliates of Emerald Oil, Inc. or Emerald WB LLC that own or control leasehold interests or Gas from leasehold interests located within the Area of Dedication at any time while this Agreement remains in effect. Producer and Gatherer are sometimes referred to herein individually as a "Party" and collectively as the "Parties".

RECITALS

A.           Producer is a working interest owner in certain oil and gas leases, wells, and/or lands within the area described in Exhibit "A" attached hereto and by reference made a part hereof (the "Area of Dedication"), and may acquire additional interests in oil and gas leases and/or lands within the Area of Dedication during the term of this Agreement (such current and future interests are referred to as the "Leases").

B.           Producer desires to have Gatherer receive, gather and redeliver all of the Gas owned by Producer which is produced from the Wells (as defined herein) and Leases within the Area of Dedication.

C.           Gatherer desires to receive Producer's Gas at the Receipt Points and redeliver Producer's Gas at the Delivery Points (as such terms are defined herein), utilizing the facilities constructed, owned and operated by Gatherer.

D.           The Parties entered into that certain Gas Dedication and Gathering Agreement dated effective July I , 2014, as amended by that certain Amendment No. 1 dated effective November 19, 2014 (the "Original Agreement"),and desire now to amend and restate the Original Agreement in its entirety, effective as of July 1, 2014, to address and incorporate additional facilities to be constructed and operated by Gatherer at the request of Producer to receive Producer's Gas, from the same Initial System DSUs as identified in Exhibit B-1 herein at certain new "Infill Receipt Points" in exchange for additional consideration to Gatherer.

E.           The Parties also desire now to name and include Emerald WB LLC as a Producer Party to this Agreement and to have Emerald WB LLC ratify the Original Agreement.

Now therefore, in consideration of the mutual covenants and agreements contained in this Agreement, the Parties agree as follows:

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ARTICLE I
REPRESENTATIONS & COMMITMENTS OF PRODUCER

1.1           Producer's Representations. Producer represents and warrants to Gatherer, its successors and assigns, that Producer has the right to operate the Wells listed on Exhibit B-2 and owns and has the right to dedicate and commit for physical delivery to and gathering by Gatherer, Producer 's Gas as defined in Section 1.2 below, and that Producer has constructed, intends to construct, or shall cause to be constructed, the facilities necessary, if any, to enable Producer to deliver to Gatherer at the Receipt Points all of Producer's Gas, in accordance with the terms and provisions of this Agreement, as well as any other facilities committed to by Producer under this Agreement.

1.2           Dedication. Producer hereby dedicates and commits to the performance of this Agreement and all of the terms and conditions herein for the Primary Term, as defined herein, as a covenant running with the land the following: (i) all of Producer's working interest share of Gas produced from the Wells operated by Producer; and (ii) all of Producer's working interest share of Gas from wells operated by parties other than Producer in which Producer takes its share of production in kind, if applicable (collectively "Producer's Gas"). Notwithstanding the foregoing, Producer's Gas shall not include: (i) Gas subject to a prior Gas dedication as of the Effective Date of this Agreement for the minimum duration of that prior Gas dedication; (ii) Gas produced from any lands or Leases that Producer in the future acquires in the Area of Dedication that are subject to a prior Gas dedication entered into by Producer's predecessor-in-interest for the minimum duration of the prior Gas dedication; (iii) Gas from Leases that are subject to a Temporary Release (for so long as such Temporary Release remains in effect) or a Permanent Release, all in accordance with the terms of this Agreement; and (iv) Gas produced from any Leases otherwise subject to this Agreement that are no longer held by production or upon their termination, expiration or release if such Leases are not cured, renewed, top leased, re-acquired or newly acquired in whole or in part by Producer, its successor-in-interest, their respective Affiliates, or any of their respective officers, directors, employees, agents or representatives. Subject to the remaining terms of this Agreement, including the rights of Producer in the event of a Temporary Release or Permanent Release, as defined herein, either exclusion applies only for the remaining minimum duration of the prior Gas dedication, Producer will take all action necessary not to extend the duration of such prior Gas dedication, and upon the expiration of that prior Gas dedication, such interest will automatically be dedicated and committed hereunder. Producer shall promptly furnish Gatherer with notices of the termination of all prior Gas dedication arrangements and the anticipated date of first delivery of those volumes to Gatherer's Gas System. Producer covenants to deliver all of Producer's Gas to Gatherer at the Receipt Points without other disposition except as otherwise provided in this Agreement.

1.3          Producer's Reservations.

i.            Producer, as a reasonable and prudent operator, hereby expressly reserves the following rights with respect to Producer's Gas and the Leases subject hereto:

a.           The right to use and consume the Gas produced from the Leases prior to delivery to Gatherer for the following purposes:

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(i)          For consumption as fuel in the development and operation of the Leases from which the Gas is produced.

(ii)         For delivery to the lessors and owners of overriding royalties or other interests in the Leases, if such lessors and owners are entitled to use such Gas or take such Gas in kind under the terms of the Leases and other definitive instruments creating their interests entered into (1) prior to the Effective Date, with respect to Leases owned by Producer at the Effective Date, or (2) prior to the date such Leases are acquired by Producer, with respect to Leases acquired by Producer after the Effective Date.

(iii)        For consumption as fuel in the operation of the facilities which Producer may install in order to deliver Gas hereunder in accordance with the terms hereof.

(iv)        Reasonable and customary amounts of Gas for its operational needs including gas lift (estimated not to exceed 500 Mcfd as of the Effective Date) and secondary or tertiary recovery projects to the extent communicated to Gatherer pursuant to Section 2.7.

b.           The right to pool or unitize the Leases (or any portion thereof) with other lands and leases. In the event of any such pooling or unitization, the Agreement will cover Producer's interest in the pool or unit and the Gas attributable thereto to the extent that such interest is derived from Producer's interest in the Leases.

ii.         Producer reserves the right to operate its Leases and Wells free of any control by Gatherer and in such a manner as Producer, in its sole discretion, may deem advisable, including without limitation, the right to enter into farmouts of any Lease subject to this Agreement, to abandon any Well and surrender any Lease. Producer reserves the right to determine the maximum efficient rate of flow for any Well (including the right to curtail production due to low market demand for Gas) and shall not be required to produce any Well or Wells in any manner which in its sole judgment and discretion would not constitute good operating practice, nor shall Producer be obligated to drill additional Wells or to deepen, repair or rework any existing Wells.

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1.4          Release Rights.

i.            Temporary Release. Notwithstanding any other provision herein, during any period after the Initial System In-Service Date, as defined in Section 2.4, when Gatherer is unable or fails to accept delivery of any of Producer's Gas in accordance with the terms of this Agreement for any reason whatsoever, including, without limitation, curtailment, Force Majeure or maintenance affecting Gatherer's Gas System or any downstream pipeline or processing plant, and there exists no uncured material breach of this Agreement on the part of Producer, then Producer m temporarily elect to deliver the quantities of Producer's Gas which Gatherer has failed to or is unable to accept to alternative gathering facilities, upon delivering written notice to Gatherer of its intent to do so (a "Temporary Release"). Failure of Gatherer to respond (or accept delivery of the Excess Volumes of Producer's Gas) within twenty-four (24) hours to a waiver request from Producer shall be deemed to be a confirmation by Gatherer of a lack of capacity on Gatherer's Gas System. The Temporary Release of Producer's Gas shall only apply to those certain volumes of Producer's Gas which Gatherer is unable to so accept (the "Released Volumes"). Furthermore, during any Accounting Period in which a Temporary Release occurs, the applicable Minimum Volume for such Accounting Period shall be reduced by an amount equal to the total of Released Volumes for such Accounting Period. Within thirty (30) days after Gatherer's delivery of written notice to Producer of its ability to again accept delivery of the Released Volumes in whole or in part, the Temporary Release will terminate as to the quantity Gatherer has specified in its written notice that it is able to receive and Producer shall resume delivery of such Released Volumes to Gatherer.

ii.            Permanent Release. Except for the six (6) month period commencing as of the Initial System In-Service Date, and subject to Section 2.5 in the context of future expansion beyond the Initial System, as applicable, in the event Gatherer has not accepted delivery of the entire quantity of Producer's Gas made available by Producer at the Receipt Points for any reason whatsoever, including, without limitation, curtailment, Force Majeure or maintenance affecting Gatherer's Gas System or any downstream pipeline or processing plant, for a continuous period of ninety (90) consecutive days, or one hundred and twenty (120) days within a one hundred eighty (180) day period, Producer shall have the right to have the Leases and Wells affected thereby permanently released from this Agreement (a "Permanent Release ") by delivering written notice thereof to Gatherer within thirty (30) days after the expiration of any such ninety (90) consecutive day period or one hundred eighty (180) day period, as applicable. Furthermore, the applicable Minimum Volume for each Accounting Period remaining during the Commitment Period shall be reduced by the estimated average daily volumes subject to Permanent Release for each such Accounting Period, in accordance with estimates of anticipated volumes previously provided by Producer pursuant to Section 2.7 that would have been delivered to Gatherer's Gas System had the Permanent Release not occurred (the "Permanently Released Volumes").

1.5           Allocations. Producer shall provide to Gatherer all information reasonably requested by Gatherer to assist Gatherer in making Receipt Point allocations called for herein or required by Gatherer's normal and customary accounting or contract administration practices. The Parties shall cooperate in providing allocation information to operators of facilities downstream of the Delivery Point to assist such operators in making allocations concerning Producer's Gas.

1.6           Memorandum of Agreement. Upon execution of this Agreement, the Parties shall concurrently execute a new Memorandum of this Agreement, in substantially the same form attached as Exhibit "D" including a legal description of the Area of Dedication that corrects and replaces the Memorandum of the Original Agreement by expressly including Emerald WB LLC as a dedicating party, together with any of Producer's other Affiliates which own or control leasehold interests or Gas from leasehold interests located within the Area of Dedication, during the Primary Term or Extended Term of this Agreement. Such Memorandum shall be placed of record in each county in which the Leases are located with Producer to bear all costs. In the event of any Permanent Release or termination of this Agreement, in whole or in part, the Parties shall execute appropriate instruments to be placed of record in each county in which the Leases are located, providing notice of the amended Area of Dedication or termination of this Agreement.

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1.7           Gas Purchaser. It is understood that Producer may enter into arrangements with purchasers of Gas under which Producer's Gas may be sold to the purchaser ("Gas Purchaser" whether one or more) at or near the well pads and prior to delivery to Gatherer, or downstream of the Delivery Points. If such arrangements are entered into by Producer, Producer will require the Gas Purchaser to deliver all of Producer's Gas to Gatherer under the terms of this Agreement and, subject to the terms and provisions hereof, all of Producer's Gas shall remain dedicated and committed to this Agreement and subject to all provisions contained in this Agreement and Producer shall cause the Gas Purchaser to execute an adoption and ratification of this Agreement in a form and substance reasonably acceptable to Gatherer.

1.8           Further Arrangements. Producer commits that, during the term of this Agreement, it will maintain, or cause its Gas Purchasers, if applicable, to maintain all necessary arrangements to provide for the further transportation and disposition of Producer’s Gas at the Delivery Points. Gatherer will use reasonable efforts to enter into interconnect agreements at the Delivery Points with third party pipelines to facilitate the further transport and disposition of Producer's Gas. Further, Producer agrees that any connection fees, throughput fees or similar charges to flow Producer's Gas into a downstream interconnecting pipeline at the Delivery Points shall be borne by Producer.

1.9           Other Owner Gas. It is expressly agreed by the Parties that, except as specifically provided herein, Producer does not dedicate to the performance of this Agreement any Gas attributable to the interests of other non-Affiliate working interest owners, non-Affiliate overriding royalty owners or royalty owners ("Other Owners") in the Wells or Leases operated by Producer within the Area of Dedication. However, in the event Other Owners fail to take their shares of production in kind from time to time and such shares of production are not subject to prior dedications to third party gatherers, and Producer elects to arrange for the temporary disposition of the shares of production of such Other Owners, then the Gas attributable to such shares of Other Owners ("Other Owner Gas") shall be deemed to be "Producer's Gas"; provided, however, that such Other Owner Gas shall not thereby become dedicated to this Agreement and shall not be entitled to receive the highest priority of service afforded Producer's Gas pursuant to Section 3.5 without ratification or other formal agreement by the Other Owners, and such Other Owners shall retain their right and obligation to take their share of production in kind. To the extent Producer tenders Other Owner Gas, Producer represents and warrants to Gatherer, its successors and assigns, thatProducer bas the right to deliver for gathering to Gatherer, the allocated share of Other Owner Gas tendered by Producer and indemnifies Gatherer accordingly.

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ARTICLE II
FACILITIES

2.1          Gatherer 's Gas System. Gatherer will construct, operate and maintain a Gas gathering system comprised of the Initial System, and any Future Receipt Points, Future Delivery Points, additional Field Compression and expansions of Gatherer's Gas System constructed pursuant to Section 2.5 (collectively "Gatherer's Gas System" ) located as necessary to enable Gatherer to receive and gather Producer's Gas from the Area of Dedication at the Receipt Points and redeliver an equivalent Thermal Content of Producer's Gas, less Fuel, Field Condensate, and Lost and Unaccounted for Gas as defined herein, to Producer or Producer's designee at the Delivery Points. Gatherer shall construct and operate Gatherer's Gas System in a workman-like manner and in accordance with good oilfield practices and in compliance with any applicable permits and licenses and all applicable rules, laws and regulations. Gatherer's Gas System will consist of:

L "Gathering Lines" means various pipeline gathering facilities from the Receipt Points to the Delivery Points, together with appurtenances thereto, with sufficient capacity across Gatherer's Gas System to receive, gather and deliver Producer's Capacity, as defined in Section 3.1, attributable to such Receipt Point (as defined immediately below).

ii. "Receipt Points" shall be at the inlet of Gatherer's metering facilities located at the locations described on Exhibit "B" as RP1 through RP8 (the "Initial Receipt Points") and as RP10 through RP14 and RP16 (the "Infill Receipt Points"), together with any additional locations installed as part of any expansion of Gatherer's Gas System beyond the Initial System (the "Future Receipt Points"), and shall mean the facilities needed to connect Producer's Wells or Producer's facilities described below in Section 2.3 to the Gathering Lines, including metering and telemetry equipment, as may be further depicted on Exhibit "B" and Exhibit "B-2". Gatherer shall furnish, own and operate all Receipt Point meters.

iii. "Delivery Points" include the facilities required to redeliver an equivalent Thermal Content of Producer's Gas to Producer or its designee at locations described on Exhibit "B" (the "Initial Delivery Points"), together with any additional locations installed as part of any expansion of Gatherer's Gas System beyond the Initial System (the "Future Delivery Points"). Gatherer will use its commercially reasonable efforts and Producer will support and assist Gatherer to obtain physical Delivery Point interconnections with downstream third party facilities. Producer shall bear its pro rata share of all Actual Construct Costs of interconnection of Gatherer's Gas System with third party facilities with the interconnection to be owned and operated by Gatherer. Gatherer shall furnish, own and operate all Delivery Point meters if such meters are not furnished, owned and operated by third party operators of downstream interconnecting third party facilities.

iv. "Field Compression" includes compression facilities appurtenant to Gatherer's Gathering Lines, as needed to provide the Nominal Average Pressure, as defined herein, at the Initial and Infill Receipt Points, and a pressure with respect to the transport of Gas on the Gathering Lines or the redelivery of Gas at the Initial Delivery Points at the pressures prevailing at the known interconnecting facilities as identified on Exhibit "B" (the "Initial Compression Facilities "), together with any additional compression installed as part of any expansion of Gatherer's Gas System beyond the Initial System pursuant to this Agreement. As part of the Field Compression facilities, Gatherer may install, at its sole cost and expense, which costs shall be expressly excluded from the Actual Construct Costs, a dehydration system such as a TEG or EG dehydration system operating up to 740 Psig with stabilizer vessel and reboilers to eliminate excess water from the Gas stream and minimize the hazards presented by hydrate formation. Field Compression shall be owned and operated by Gatherer and Gatherer shall assess a "Compression Fee”" as further described in this Agreement and Exhibit "E".

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v. The portion of Gatherer's Gas System that consists of the Initial System as described below, will be designed and constructed to: (a) be capable of handling the Gas volumes existing and anticipated from the drilling spacing units described on Exhibit "B-1" (the "Initial System DSUs"); (b) provide a nominal average operating pressure at the individual Initial Receipt Points, RP 1 through RP8 as described more specifically on Exhibit "B", of approximately 55 Psig (the "Nominal Average Pressure" ) based on eight thousand (8000) Mcfd in the aggregate across the Initial System; and (c) provide the Nominal Average Pressure at the individual Receipt Points, RP10 through RP14 and RP16 as described more specifically on Exhibit "B" so long as no single Receipt Point exceeds one thousand (1000) Mcfd. In the event the nominal average operating pressure at any Receipt Point is in excess of the Nominal Average Pressure during any Accounting Period in which Producer's Gas volumes are 8000 Mcfd or less, Producer may provide written notice (a "Compression Notice ") to Gatherer requesting that Gatherer decrease the nominal average operating pressure at such Receipt Point. If the nominal average operating pressure at such Receipt Point is not brought within the range of the Nominal Average Pressure within forty-five (45) days following receipt of the Compression Notice, Producer shall have the right to install compression facilities upstream of such Receipt Point, at Producer's sole cost and expense, whereupon Producer shall not owe any Compression Fees for Producer's Gas delivered to such Receipt Point, until such time as the amount of Compression Fees otherwise attributable to such Gas, but retained by Producer, is equal to the total of Actual Construct Costs incurred by Producer to install such compression facilities. In the event the nominal average operating pressure at any Receipt Point is in excess of the Nominal Average Pressure during any Accounting Period in which Producer's Gas volumes are more than 8000 Mcfd, Gatherer shall propose a plan to modify or expand its Gas Gathering System as necessary to achieve and maintain the Nominal Average Pressure at the affected Receipt Points, and shall modify or expand its Gas Gathering System as necessary to achieve and maintain the Nominal Average Pressure at the affected Receipt Points within forty-five (45) days following receipt of the Compression Notice. Subject to Force Majeure, in the event Gatherer fails or elects not to modify or expand its Gas Gathering System as necessary to achieve and maintain the Nominal Average Pressure at the affected Receipt Points within forty-five (45) days following receipt of the Compression Notice, Producer shall have the right to install compression facilities upstream of such Receipt Point, at Producer's sole cost and expense, whereupon Producer shall not owe any Compression Fees for Producer's Gas delivered to such Receipt Point, until such time as the amount of Compression Fees otherwise attributable to such Gas, but retained by Producer, is equal to the total of Actual Construct Costs incurred by Producer to install such compression facilities.

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2.2            Rights-of-Way. At the time of executing this Agreement, Producer has completed its acquisition of rights-of-way (the "ROW" or "ROWs") from certain landowners within the Area of Dedication ("Landowners") authorizing the construction, installation and operation of multiple pipelines within the same right-of-way corridor. Producer shall be able to assign the ROWs in part to Gatherer, so as to grant Gatherer the right to install a single gas gathering line and related facilities in the corridor of the ROW in connection with the construction, installation and operation of the Initial System. Due to Producer's existing relationship with the Landowners and in an effort to maximize efficiency, Producer will continue to interface directly with the Landowners until such time as the ROWs have been partially assigned to Gatherer, except as described below. Producer has tendered compensation to the respective Landowner and has recorded the respective ROW with the McKenzie County Clerk and Recorder. With respect to each ROW, until such time as Producer assigns the ROWs to Gatherer, Producer shall indemnify and hold harmless Gatherer, its Affiliates, and their respective employees, officers, directors, contractors and subcontractors (collectively, "Gatherer Indemnified Parties") from and against any and all trespass claims or claims arising out of the invalidity of any ROW brought by third party landowners arising from Gatherer's ingress to, egress from, entry upon, and use of such ROWs for survey, construction, installation and operation of the Gas Gathering System except to the extent arising from the gross negligence or willful misconduct of Gatherer Indemnified Parties.

Producer shall use commercially reasonable efforts to obtain any third party consents required to assign its ROWs to Gatherer (each a "Consent to Assign "). In the event Producer, despite commercially reasonable efforts is unable to obtain any Consent to Assign Producer shall continue to hold such ROW for the benefit of Gatherer until such time as the Consent to Assign is obtained. Concurrently with the execution of this Agreement, Producer shall partially assign the ROWs to Gatherer, pursuant to the form of assignment attached hereto as Exhibit "G", and within thirty (30) days of receipt of detailed invoice and reasonably requested supporting documentation, Gatherer shall pay Producer twenty percent (20%) of the actual and direct costs incurred in obtaining the ROWs (based on five (5) pipelines allowed within a ROW and adjusted up or down for fewer or more pipelines properly located within a single ROW).

However, if Gatherer determines that any ROW is unnecessary for the Initial System or is insufficient, lacking, or otherwise defective, such that Gatherer in its reasonable discretion must acquire a new right-of-way in lieu thereof, such ROW shall not be assigned to Gatherer and Gatherer shall not pay any portion of the costs associated with such ROW.

Gatherer may proceed to interface with and acquire the real property interests it requires, including additional rights-of-way or amendments to ROWs to serve the Infill Receipt Points directly from the Landowners or other owners of such interests ("Gatherer ROWs"). In the event that Gatherer, despite commercially reasonable efforts, is unable to obtain any right-of-way deemed necessary for Gatherer in its reasonable discretion to construct and install the portions of the Initial System serving the Infill Receipt Points prior to May 31, 2015 (an "Outstanding ROW''), Gatherer may proceed with re-routing the course of the affected portion of the Initial System and acquire additional Gatherer ROWs to circumvent any uncooperative third party landowners with Gatherer to bear such Outstanding ROW costs and re-routing costs in the aggregate up to Eighty-Three Thousand Three Hundred and Thirty-Three dollars($83,333), which costs shall not be included in the Actual Construct Costs. In the event the Outstanding ROW costs are anticipated to exceed $83,333 the Parties shall promptly meet to develop a mutually agreeable plan to complete acquisition of Outstanding ROW. The Initial System Target In-Service Date shall be extended, as an Excused Delay as defined in Section 2.4 below, by the number of days, if any, that the construction and installation of the Initial System is delayed in order to acquire Outstanding ROW or agree on a course of action, or otherwise due directly to the Outstanding ROW.

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2.3            Producer's Facilities and Construction. Producer, at its own expense, shall construct, equip, maintain and operate all facilities upstream of the Receipt Points necessary to enable Producer to deliver all of Producer's Gas to Gatherer at the Receipt Points, including without limitation, flowlines and pipelines to move Producer's Gas from its Wells to the Receipt Points as identified in Exhibits "B" and "B-2" and mechanical separation equipment and all necessary facilities or equipment arising from any dual, split or additional connects if Producer's Wells are subject, in whole or in part, to existing dedications and connections to third party gatherers prior to the Effective Date. Producer shall be responsible for the delivery of Producer's Gas at pressures sufficient to enter the respective Receipt Point at the Nominal Average Pressure.

2.4            Initial System. The "Initial System" will consist of the initial facilities of Gatherer, described generally above and on Exhibit "B", as necessary to connect the Initial Receipt Points and Infill Receipt Points with the Initial Delivery Points, also described on Exhibit "B". The Parties have agreed upon the configuration, design and construction of Gatherer's Gas System and have deemed the Initial System as sufficient to serve all of Producer's Minimum Volume commitment stated in Exhibit "E", and that the Initial System is sufficient to serve all of Producer's anticipated volumes of Producer's Gas from the Wells identified on Exhibit "B-2" (collectively, the "Initial System Wells")at the Initial Receipt Point or Infill Receipt Point listed in the column "Gatherer Receipt Point Construction Responsibilities" next to each such Well.

Subject to events of Force Majeure, severe winter weather, frost laws, road restrictions and other requirements or delays imposed by government agencies including without limitation delays in issuing ROWs on federal lands needed for the portion of Gatherer's Gas System serving the Infill Receipt Points, whether or not within the scope of Force Majeure that would make the diligent pursuit of similar construction or installation operations unreasonable for a reasonably prudent McKenzie County North Dakota gatherer faced with similar conditions (whether one or more, "Excused Delays "), Gatherer shall diligently construct, install and complete (y) the portion of Gatherer's Gas System serving the Initial Receipt Points as described on Exhibit "B" and Exhibit "B-2" on or before May 1, 2015 (the "Start-Up Target Date "), and (z) all of the Initial System including the Initial and Infill Receipt Points, on or before August 31, 2015, as extended by the number of Days equal to any Excused Delay event (the "Initial System Target In-Service Date"). The Parties each agree that their respective obligations to meet the Start-Up Target Date are on a reasonable commercial efforts basis with no credits or penalties applicable to either Party for non-achievement. Producer acknowledges and agrees that any receipt, gathering and delivery of Gas by Producer prior to the Initial System In-Service Date shall incur the applicable Gas Gathering Fees and shall be provided on an interruptible basis at Gatherer's sole discretion as Gatherer may be completing the installation and construction of its Gas System and may also need to undertake calibration and other activities to achieve the Initial System In-Service Date during that period, provided however, that Gatherer shall notify Producer 24 hours or as soon as practicable prior to any activities of Gatherer that may reasonably be expected to cause an interruption or otherwise prevent Gatherer from receiving Gas from any Receipt Point from which Gatherer has previously accepted Gas, and Gatherer shall keep Producer fully informed of the progress of such activities and any anticipated resumption of service from such Receipt Point(s). The date on which Gatherer has completed the construction and installation of the Initial System, in its entirety so as to be capable of receiving Producer's Gas from all of the Initial Receipt Points and Infill Receipt Points identified on Exhibits "B" and "B-2'', shall be the "Initial System In-Service Date" . For avoidance of doubt, such completion by Gatherer shall be a deemedachievement of the Initial System In-Service Date notwithstanding the Initial System's partial or complete inability to accept and flow Gas on the Initial System when such inability arises solely from Producer's delay or failure to complete its responsibilities and obligations under this Agreement, as extended by Force Majeure or in the case of delay or failure to complete re-run piping if caused by frost laws imposed by government agencies.

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i.            In the event, subject to Force Majeure or Excused Delay, Gatherer fails to complete its construction of the Initial System, in its entirety per Section 2.4, Exhibit "B" and Exhibit "B-2", on or before the Initial System Target In-Service Date, and Producer has completed all facilities upstream of the Initial and Infill Receipt Points per Section 2.3, Exhibit "B" and Exhibit "B-2", and is otherwise ready, willing and able to deliver Producer's Gas to that portion of the Initial System that is not completed, the following shall occur:

a.           the applicable Minimum Volume for each Accounting Period, or portion thereof, between the Initial System Target In-Service Date and the Initial System In-Service Date, shall be reduced by the estimated average daily volumes of Producer's Gas from the Initial System In-Service Date Wells for each such Accounting Period that would have been otherwise delivered to Gatherer's uncompleted portion of the Initial System during such Accounting Periods, in accordance with estimates of anticipated volumes previously provided by Producer to Gatherer pursuant to Section

2.7 (the "Gatherer's Initial System Delay Pre-ln service Volumes"); and

b.           Producer shall receive a credit against the Gas Gathering Fees owed by Producer in that Accounting Period (or if none are owed in that Accounting Period, beginning in the next occurring Accounting Period in which Gas Gathering Fees are owed by Producer and continuing for each successive Accounting Period until the credit is used in full, with the credit amount equal to Two dollars and Fifty cents ($2.50) per Mcf for the Gatherer's Initial System Delay Pre-In service Volumes, up to a maximum total credit of Two Million dollars ($2,000,000) for all Gatherer's Initial System Delay Pre-In service Volumes under this Agreement together with all "Gatherer's Initial System Delay Pre-In service Barrels" as defined under the Related Dedication Agreements described in Section 8.3 herein ("Initial System Pre-ln service Credit'').

ii.            In the event Gatherer has completed its construction of the Initial System, in its entirety per Section 2.4, Exhibit "B" and Exhibit "B-2", on or before the Initial System Target In-Service Date, but, subject to Force Majeure or in the case of delay or failure to complete re-run piping if caused by frost laws imposed by government agencies, Producer has failed to complete all facilities upstream of the Initial and Infill Receipt Points per Section 2.3, Exhibit "B" and Exhibit "B-2'', and Gatherer is otherwise ready, willing and able to receive and gather Producer's Gas on that portion of the Initial System, then the following shall occur:

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a.           the applicable Minimum Volume for each Accounting Period, or portion thereof, between the Initial System Target In-Service Date and the Initial System In-Service Date, shall be reduced by the estimated average daily volumes of Producer's Gas from the Initial System In-Service Date Wells for each such Accounting Period that would have been otherwise delivered to the Initial System during such Accounting Periods if Producer had completed all facilities upstream of the Initial and Infill Receipt Points in accordance with estimates of anticipated volumes previously provided by Producer to Gatherer pursuant to Section 2.7 (the "Producer's Initial System Delay Pre-In service Volumes").

b.           Producer shall pay Gatherer an amount equal to Two dollars and Fifty cents ($2.50) per Mcf for the Producer's Initial System Delay Pre-In service Volumes beginning in the first Accounting Period following the Initial System In-Service Date and continuing for each successive Accounting Period until the payment is satisfied in full, up to a maximum total payment of Two Million dollars ($2,000,000) for all Producer's Initial System Delay Pre-In service Volumes under this Agreement together with all "Producer's Initial System Delay Pre-In service Barrels" as defined under the Related Dedication Agreements described in Section 8.3 herein ("Initial System Pre-In service Fee").

111.            In addition to Producer's remedies under Section 2.4(i), in the event Gatherer fails to complete its construction of the Initial System, in its entirety per Section 2.4, Exhibit "B" and Exhibit "B-2'', on or before the date that is sixty (60) Days after the Initial System Target In-Service Date, and Producer has completed all facilities upstream of the Initial and Infill Receipt Points per Section 2.3, Exhibit "B" and Exhibit "B-2" and is otherwise ready, willing and able to deliver Producer's Gas to that portion of the Initial System that is not completed, Producer shall have the option, exercisable in its sole discretion, to elect by written notice to Gatherer to construct and install the remainder of the Initial System, at Producer's sole cost and expense, whereupon Producer shall not owe any Gas Gathering Fees for any Gas delivered to the Initial and Infill Receipt Points or flowing through that portion of the Initial System constructed and installed by Producer, until such time as the amount of Gas Gathering Fees otherwise attributable to such Gas, but retained by Producer, is equal to one hundred and ten percent (110%) of the total of Actual Construct Costs incurred by Producer to complete the construction and installation of the remainder of the Initial System.

iv.            Gatherer shall keep Producer reasonably informed of the progress on the construction and installation of the Initial System, and any Excused Delays in connection therewith. Producer shall have the right to have its representative present during any onsite construction or installation operations of the Initial System.

2.5           Future Expansion Beyond the Initial System. After installation of the Initial System, Gatherer will install and connect such Future Receipt Points, Future Delivery Points, additional Field Compression and expansions of Gatherer's Gas System, including but not limited to, installing additional or "looped" gathering lines or a larger diameter pipe that Gatherer in its sole judgment determines are necessary or desirable to gather Producer's Gas dedicated under this Agreement from subsequent completed Wells drilled or acquired by Producer within the Area of Dedication as set forth in this Section 2.5. For avoidance of doubt, any expansion of Gatherer's Gas System to serve Producer's Wells located outside of the Area of Dedication is not contemplated by or covered under the scope of this Agreement. The Parties agree that Gatherer will own and operate any and all future expansions to Gatherer's Gas System including any Producer Built Gathering Facility, as defined in Section 2.6 herein.

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i.            In addition to providing Gatherer with annual drilling plans and quarterly updates to those plans under Section 2.7 below, Producer shall give Gatherer written notice (a "Connection Notice") one hundred twenty (120) to ninety (90) Days prior to the completion of any new Well located within the Area of Dedication but outside of the Initial System DSUs, or within ten (l0) days after acquiring any such completed Well, specifying: the Well name; Well location; the location of the nearest Receipt Point or proposed Future Receipt Point, as applicable, for such Well; drilling, completions and anticipated recompletion details; the minimum anticipated initial and annual volumes of Producer 's Gas from such Well together with the anticipated available volumes of Producer's Gas and Other Owner Gas from the drilling spacing unit ("DSU' ) in which the Well is located as may be requested by Gatherer; and if a Distant Expansion under subsection (iv) below applies, also specifying up to four (4) DSUs that are each directly adjacent to or cornering the DSU (the "Contiguous DSUs ") of the Distant Well (defined below) for possible Permanent Release at Producer's sole discretion under subsection (iv)(a) below if (iv)(a) applies and the anticipated available volumes of Producer's Gas from the four (4) Contiguous DSUs as may be requested by Gatherer (the anticipated volumes from the DSU of the Distant Well and the four (4) Contiguous DSU volumes if requested, are collectively the "Connection Volumes").Concurrently with its Connection Notice under this Agreement , Producer shall provide Gatherer with "Connection Notices" concerning the Well as required under the Related Dedication Agreements described in Section 8.3 of this Agreement. If a Well that is the subject of a Connection Notice is not completed within one hundred twenty (120) days of the Connection Notice, following good faith discussions with Producer, Gatherer shall then have the option to deem the Connection Notice as invalid and of no further effect.

ii.         In the event the Well, or the Future Receipt Point, if applicable, as identified in the Connection Notice requires less than or equal to a three (3) mile expansion of Gatherer's Gas System from an existing Receipt Point or Delivery Point, as Gatherer's Gas System exists as of the date of the Connection Notice (a "Nearby Well"), Gatherer shall have the first option to construct, install and place into operation an expansion of Gatherer's Gas System to connect to the Nearby Well at Gatherer's sole cost and expense, in exchange for Gatherer's ability to charge Producer an additional fee per Mcf for any Gas from such Nearby Well or any other Well Producer flows through such expansion constructed by Gatherer based on the sample calculation set forth in Exhibit "H," such that Gatherer has recouped its Actual Construct Costs incurred by Gatherer to construct the expansion plus incremental operating expenses and capital expenditures, including capital expenditures needed to modify or upsize the Initial System or a prior expansion of the Initial System to accommodate the Connection Volumes, over a five (5) year period and receive a seven and a half percent (7.5%) internal rate of return ("IRR" as calculated by the Microsoft Excel IRR function :financial formula) and trued up quarterly ( "Expansion Fee''). For the avoidance of doubt the Expansion Fee shall be in addition to all other Gas Gathering Fees due for the Connection Volumes and such Expansion Fee shall be reduced equitably if Gatherer, in its sole discretion, elects to construct and install an expansion of larger size or greater capacity than requested by Producer in its Connection Notice or required to serve Producer's Connection Volumes.

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m.           Subject to Force Majeure and the condition that Producer has in fact completed such a Nearby Well, in the event Gatherer fails to timely construct, install and make available for operation on or before the later of ninety (90) days from receipt of the Connection Notice or the date the Well identified in the respective Connection Notice is completed, an expansion of Gatherer's Gas System to connect the Connection Volumes from the Nearby Well, following good faith discussions with Gatherer, Producer shall then have the option either to:

a.           Construct and install an expansion of Gatherer's Gas System to connect Gatherer's Gas System existing at that time to the Nearby Well, at Producer's sole cost and expense, in exchange for Producer receiving a credit against any Base Fee component of the Gas Gathering Fees otherwise owed Gatherer for any Gas from such Nearby Well or any other Well flowing through such expansion constructed by Producer, until such time as the amount of the Base Fee component of the Gas Gathering Fees otherwise attributable to such Gas, but retained by Producer, is equal to the total of Actual Construct Costs incurred by Producer to construct the expansion based on the sample calculation set forth in Exhibit "H," such that Producer has recouped its Actual Construct Costs incurred by Producer to construct the expansion plus incremental operating expenses and capital expenditures, including capital expenditures needed to modify or upsize the Initial System or a prior expansion of the Initial System to accommodate the Connection Volumes, over a five (5) year period and receive a seven and a half percent (7.5%) IRR and trued up quarterly ( "Expansion Credit"); or

b.           Subject to Section 1.4(ii), obtain a Permanent Release from this Agreement of the Nearby Well and any of the Leases located within the same DSU as the Nearby Well but not located within an Initial System DSU.

iv.         In the event the Well, or the Future Receipt Point or Delivery Point, if applicable, as identified in the Connection Notice requires more than a three (3) mile expansion of Gatherer's Gas System, as Gatherer's Gas System exists as of the date of the Connection Notice ("Distant Well"), or involves a connection of Gatherer's Gas System with facilities of third parties not connected to Gatherer's Gas System as of the date of the Connection Notice (one or both situations, a "Distant Expansion ") , the Parties shall promptly pursue good faith negotiations of mutually agreeable terms and conditions of such an expansion and strive to enter into a definitive separate agreement or written amendment setting forth a definitive agreement as to such Distant Expansion. In the event the Parties have not reached agreement, on or before the later of ninety (90) days from receipt of the Connection Notice or the date the Well identified in the respective Connection Notice is completed, for the terms of such a Distant Expansion of Gatherer's Gas System, following good faith discussions with Gatherer, Producer shall have the option to:

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a.    Subject to Section l .4(ii), obtain a Permanent Release from this Agreement of any of the Leases located within the DSU of the Distant Well, and the four (4) Contiguous DSUs but only if such Leases are not located within an Initial System DSU.

v.           Gatherer shall keep Producer reasonably informed of the progress on the construction and installation of any expansion of Gatherer's Gas System. Producer shall have the right to have its representative present during any onsite construction or installation operations of any expansion of Gatherer's Gas System.

2.6           Construction or Expansion by Producer. In the event Producer elects to construct, install or expand any portion of Gatherer's Gas System pursuant to an express right provided under this Agreement, which expressright does not extend to a gas processing facility or compression above what is required for a similar gas gathering facility (a "Producer Built Gathering Facility"),the following shall apply:

i.            Each Producer Built Gathering Facility shall be constructed and installed by Producer according to the reasonable design and construction specifications of Gatherer. In constructing and installing the Producer Built Gathering Facility, Producer shall have the right to utilize any available gas pipeline right-of-way or easement rights of Gatherer and any materials of Gatherer, at cost.

ii.         Upon completion of any Producer Built Gathering Facility, Producer shall assign such Producer Built Gathering- Facility to Gatherer, at no charge to Gatherer, but expressly subject to the terms of this Agreement, whereupon it shall become part of Gatherer's Gas System.

iii.         If Producer has incurred Actual Construct Costs pursuant to Section 2.5(iii)(a), once Producer has recouped all of such Costs pursuant to Section 2.5, Gatherer may begin to assess the applicable Base Fee component of Gas Gathering Fees for all Gas delivered by Producer into or flowing through such Producer Built Gathering Facility. Gatherer may begin to assess all other components of the Gas Gathering Fees for all Gas delivered by Producer beginning upon the commencement of receipt into or flow through such Producer Built Gathering Facility.

iv.         For the avoidance of doubt, for purposes of determining whether Producer has delivered the Minimum Volume in any Accounting Period pursuant to the terms and conditions set forth on Exhibit "E", any Gas delivered during such Accounting Period for which Producer does not owe any Base Fee component of the Gas Gathering Fees pursuant to its incurrence of Actual Construct Costs pursuant to Article 2 of this Agreement shall be included in the Delivered Volume.

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2.7           Producer's Anticipated Volumes. Upon the execution of this Agreement, and thereafter by October first (1st) of each calendaryear, Producer shall communicate its drilling, completion and recompletion plans to Gatherer in writing, including locations, anticipated spud dates, together with anticipated volumes to be delivered to Gatherer, for the next calendar year. Additionally, during Gatherer's construction of facilities to serve the Infill Receipt Points, Producer shall promptly notify Gatherer of any delay in its drilling and completion schedules for the Wells identified in Exhibit "B-2", including without limitation delays in completion of any Wells on Exhibit "B-2" later than May 1, 2015. At all other times during the Primary Term or Extended Term, no later than the last day of each calendar quarter, Producer shall notify Gatherer in writing with reasonable detail of any changes or additions to its drilling plans for the succeeding twelve (12) Accounting Periods. In addition to providing Connection Notices, pursuant to Section 2.5(i), Producer shall provide updates to Gatherer, as needed, of specific drilling and completion plans, actual initial production dates, and additional volumes from Other Owner Gas or from prior dedications.

2.8           Ownership of Facilities. Producer expressly does not by the terms of this Agreement, sell, transfer or assign unto Gatherer any title or interest whatsoever in the Leases or any pipelines or other equipment of any nature ownedor used by Producer in the operation of Producer's Wells and the Leases. Gatherer expressly does not by the terms of this Agreement, sell, transfer or assign unto Producer any title or interest whatsoever in Gatherer's Gas System, or any pipelines or other equipment of any nature owned and used by Gatherer in the operation of Gatherer's Gas System or its performance of services under this Agreement.

ARTICLE III
GATHERING SERVICE

3.1           Producer's Capacity. Commencing on the Initial System In-Service Date, Gatherer shall make available Capacity equal to Producer's anticipated volumes of Producer's Gas to be delivered pursuant to Sections 2.4 and 2.7 ("Producer's Capacity")in the aggregate, for the benefit of Producer's Gas, subject to Force Majeure. On a daily basis, any capacity available in the Gatherer's Gas System in excess of the lesser of Producer 's Capacity or the actual amount of Producer's Gas nominated by Producer to Gatherer each Day hereunder, shall be available to Gatherer for Third Party Gas volumes on such Days. Producer's Capacity shall be adjusted upward by additional Connection Volumes served by expansions of Gatherer's Gas System pursuant to Section 2.5 of this Agreement, and downward by Permanently Released Volumes pursuant to Section l .4(ii) of this Agreement.

3.2           Gathering. Subject to the terms and conditions of this Agreement, Gatherer shall receive at the Receipt Points and gather Producer's Gas utilizing Gatherer's Gas System, up to Producer's Capacity, and redeliver an equivalent Thermal Content quantity of Gas, less Fuel, Field Condensate, and Lost and Unaccounted for Gas, to Producer or its designee at the Delivery Points in consideration of Producer'spayment of the Gas Gathering Fees provided on Exhibit "E". To the extent of available capacity, Gatherer also agrees to receive and gather any of Producer 's Gas in excess of Producer's Capacity and Other Owner Gas on an interruptible basis and to redeliver to Producer or its designee the equivalent Thermal Content quantity of such Gas, less Fuel, Field Condensate, and Lost and Unaccounted for Gas to Producer or its designee at the Delivery Points in consideration of Producer's payment of the Gas Gathering Fees provided on Exhibit "E" for such Producer's Gas and Other Owner Gas. For purposes of Thermal Content determination under this Agreement, Gas will be measured by Gatherer using an ABB Flow Totalizer with volumes adjusted for gas composition and reported in Btus. Gas sample analysis will be made at least quarterly and analysis results will be the composition basis for the period.

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3.3           No Processing. Gatherer shall not process Producer's Gas for the removal of liquefiable hydrocarbons after receipt of Producer's Gas at the Receipt Points and prior to its delivery to the Delivery Points, other than by the use of conventional mechanical type Gas liquid separators commonly used in the industry to separate liquid hydrocarbons and free water from Gas which shall include without limitation the dehydration system identified in Section 2.1(iv). The Parties acknowledge and agree that Field Condensate may separate from Producer's Gas as a result of Gatherer's normal gathering and compression operations and that Gatherer shall be allowed to remove and retain for its own account such Field Condensate.

3.4           Third Party Gas. Producer acknowledges and understands that Gatherer will receive Producer's Gas utilizing Gatherer's Gas System which may also receive and commingle Producer's Gas with Third Party Gas delivered to Gatherer by other parties, at all times subject to Producer's Capacity and such Third Party Gas meeting the Gas Quality Specifications set forth in the attached Exhibit "F." Accordingly, the Gas delivered to the Producer or Producer' s designee at the Delivery Points may not be the same Gas, or have the same characteristics, as Producer's Gas delivered to the Receipt Points.

3.5           Priority of Service. Except for any Other Owner Gas that has not been dedicated to this Agreement by ratification or other formal agreement entered into by such Other Owner, Producer 's Gas, up to Producer's Capacity, shall be accorded highest priority on Gatherer's Gas System with respect to capacity allocations, interruptions, or curtailments. On a Receipt Point or Delivery Point basis as applicable, Producer's Gas will be the last Gas curtailed from Gatherer's Gas System in the event of an interruption or curtailment affecting specific Receipt Points or Delivery Points rather than Gatherer's Gas System as a whole, and all of Producer's Gas affected by a particular Receipt Point or Delivery Point will be treated in the same manner in the event an allocation is necessary. Gatherer agrees not to contract to provide, at any time, gathering service on Gatherer's Gas System on a basis that has a priority higher than what Producer's Gas is entitled to pursuant to this Section 3.5 and under this Agreement.

ARTICLE IV
EXHIBITS

4.1           Exhibits. All Exhibits attached to this Agreement are incorporated into and made an integral part of this Agreement by reference including the General Terms and Conditions set forth in the attached Exhibit "C" (the "GT&C').

4.2           Order of Precedence. In the event of any conflict between the terms as set out in the body of this Agreement and those set out in the GT&C, the terms in the body of this Agreement shall control.

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ARTICLE V

CON SIDERATION & FEES

5.1           Fees. Gatherer shall charge and Producer shall pay the applicable "Gas Gathering Fees" and any "Shortfall Payment" described on Exhibit "E" based on the total Mcf of Gas delivered by Producer and received at the Receipt Points. If and as applicable under Section 2.4(ii)(b), Gatherer shall charge and Producer shall pay the Initial System Pre-In service Fee. If and as applicable under Section 2.5, Gatherer shall charge and Producer shall pay the Expansion Fee.

5.2           AnnualFee Adjustments. The Base Fee, Meter Fee, Compression Fee, and Expansion Fee components of the Gas Gathering Fees may be adjusted annually during the term of this Agreement, for the prospective calendar year, the first prospective calendar year being 2020, based on the percentage change in the annual average in the "Consumer Price Index for All Urban Consumers (CPI-U) : U.S. city average - All items" which occurred in the preceding calendar year as published by the United States Department of Labor, Bureau of Labor Statistics for the previous calendar year, but shall never be less than the Base Fee, Meter Fee or Compression Fee, as applicable, set forth in Exhibit "E''.

5.3           Utilities. Producer shall furnish utilities needed for Gatherer's Gas System at the Receipt Points. In addition to the Gas Gathering Fees and utilities furnished by Producer, Gatherer shall charge and Producer shall pay its pro rata share of the actual utility costs incurred by Gatherer in connection with operating Gatherer's Gas System including any necessary power costs incurred in connection with Field Compression or with the Delivery Points. The actual utility costs shall be allocated on a pro-rata basis to each shipper of Gas on Gatherer's Gas System each Accounting Period based upon throughput of all Gas through Gatherer's Gas System during such Accounting Period.

5.4           Lost and Unaccounted for Gas. The difference between the volume of Producer' s Gas, as measured in MMBtus at the Receipt Points and the measurements provided by the interconnecting parties in MMBtus at the Delivery Points, less Field Condensate and Fuel, shall be considered as Lost and Unaccounted for Gas sustained on Gatherer's Gas System due to evaporation, measurement and other losses in transit. The Lost and Unaccounted for Gas shall be allocated on a pro-rata basis to each shipper of Gas on Gatherer's Gas System each Accounting Period based upon throughput of all Gas through Gatherer's Gas System during such Accounting Period. Gatherer shall not be responsible to Producer for the Lost and Unaccounted for Gas.

5.5           Fuel. Gatherer may retain for its own account so much Gas as reasonably necessary for Gatherer to use and consume as fuel to operate Gatherer's Gas System ("Fuel"). The Fuel shall be allocated on a pro-rata basis to each shipper of Gas on Gatherer's Gas System each Accounting Period based upon throughput of all Gas through Gatherer's Gas System during such Accounting Period.

5.6           Limitation. Notwithstanding anything to the contrary herein, the equivalent Thermal Content quantity of Producer's pro rata share of the sum of (i) all Lost and Unaccounted for Gas, and (ii) Fuel, for any Accounting Period, shall not exceed four percent (4.0%) of the equivalent Thermal Content quantity of Producer's Gas transported on Gatherer's Gas System for such Accounting Period .

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ARTICLE VI

NOTICES

6.1           Notice Process. All notices and communications required or permitted under this Agreement shall be in writing and shall be considered as having been given if delivered personally, or when received by mail, by electronic means (confirmed as received before 5 p.m. at the place of receipt), or by express courier, postage prepaid, by either Party to the other at the addresses given below. Routine communications, including monthly statements, shall be considered as duly delivered when mailed by ordinary mail or by electronic means.

6.2           Addresses for Notice. Unless changed upon written notice by either Party, the addresses for notice purposes are as follows:

TO:	Emerald Oil, Inc.
	1600 Broadway, Suite 1360
	Denver, CO 80202
	Phone: 303-595-5629
	Contact:  James Muchmore
TO:	Dakota Midstream, LLC
	1600 Broadway, Suite 1330
	Denver, CO 80202
	Phone: 202-213-5998
	Contact:  Tim Reynolds

ARTICLE VII

TERM

7.1    Primary and Extended Terms. This Agreement shall commence as of the Effective Date and shall remain in full force and effect for a primary term of fifteen (15) years (the "Primary Term") and shall continue year to year thereafter until terminated by either Party (the "Extended Term") by providing written notice of termination to the other Party at least sixty (60) days prior to the expiration of the Primary Term or any subsequent annual expiration date.

7.2    Capacity Adjustment. During any Extended Term, Producer's Capacity will be the average daily volume of Producer's Gas delivered to Gatherer's Gas System during the prior twelve (12) month period.

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7.3           Uneconomic Operations. Subject to any Force Majeure event affecting Producer's obligations to deliver Gas hereunder, in addition to all other rights of Gatherer under this Agreement, in the event the sum of actual direct costs (for the avoidance of doubt, excluding overhead, depreciation, amortization and capital expenditures) incurred by Gatherer to operate any portion of Gatherer's Gas System (the "Uneconomic Segment'') during any ninety (90) day period are in excess of the total net revenue attributable to the Uneconomic Segment (including all Gas Gathering Fees paid by Producer or any third party attributable to the Uneconomic Segment) during such ninety (90) day period, Gatherer shall have the right to send written notice (an"Uneconomic Notice" ) to Producer of its intent to terminate receipts of Gas into the Uneconomic Segment unless the Gas Gathering Fees owed by Producer for Producer 's Gas delivered to the Uneconomic Segment are increased such that Gatherer's total anticipated net revenue attributable to the Uneconomic Segment is projected to equal one hundred ten percent (110%) of Gatherer's actual direct costs (for the avoidance of doubt, excluding overhead, depreciation, amortization and capital expenditures) incurred by Gatherer to operate the Uneconomic Segment. Any increased Gas Gathering Fee shall be borne pro-rata by Producer and any third party shipper on the Uneconomic Segment according to the anticipated volumes of Producers Gas and Third Party Gas to be delivered to or flowed through the Uneconomic Segment. Within ten (10) days of Producer's receipt of notice from Gatherer, Producer shall elect by written notice sent to Gatherer either to:

i.        Accept the increased Gas Gathering Fees, or portion thereof, effective as of the beginning to the next Accounting Period, owed by Producer for Producer's Gas delivered to the Uneconomic Segment, whereupon Gatherer shall not send another Uneconomic Notice pursuant to this Section 7.3 for at least ninety (90) days; or

ii.       Obtain a Temporary Release of the Leases and Wells directly affected by the Uneconomic Segment, with Producer able to elect, by delivery of written notice to Gatherer, to obtain a Permanent Release and terminate the Agreement, insofar as it pertains to the Uneconomic Segment after one hundred eighty (180) days of Producer's receipt of the Uneconomic Notice under this Section 7.3.

ARTICLE VIII

MISCELLANEOUS

8.1           Assignment. This Agreement, including, without limitation, any and all renewals, extensions, amendments and/or supplements hereto shall extend to and inure to the benefit of and be binding upon the Parties, and their respective successors and assigns, including any purchaser of Producer's Gas or Producer's interests in the Leases that are dedicated under this Agreement or subsequent operator of the Wells, and any purchaser of Gatherer's Gas System, or any part or interest therein which are subject to this Agreement; provided, however, (i) this Agreement shall not be assigned by a Party without the prior written consent of the other Party, such consent not to be unreasonably withheld, conditioned or delayed, and (ii) no sale, assignment, conveyance or other transfer (collectively, a "Transfer") of Producer's Leases or Wells, or any part thereof or interest therein, or any part of Gatherer's Gas System, shall be made unless the transferee thereof shall assume and agree to be bound by this Agreement insofar as the same shall affect and relate to the Leases, Wells, Gatherer's Gas System or interests so Transferred. Notwithstanding the conditions and restrictions set forth on assignment in this Section 8.1, each Party retains the right to freely assign this Agreement to an Affiliate within the first year following the Effective Date. Interests owned in the Area of Dedication by a transferee of any of Producer's Leases or Wells that were owned prior to the effective date of such Transfer shall not become subject to this Agreement by virtue of such Transfer. Itis further agreed, however, that nothing herein contained shall in any way prevent a Party from pledging or mortgaging, all or any part of such Producer's Leases if Producer, or Gatherer's Gas System if Gatherer, as security under any mortgage, deed of trust, or other similar lien, or from pledging this Agreement or any benefits accruing hereunder to the Party making the pledge without the assumption of obligations hereunder by the mortgagee, pledgee or other grantee under such instrument.

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8.2           No Third Party Beneficiaries. Nothing in this Agreement, expressed or implied, confers any rights or remedies on any person or entity not a party hereto other than successors and assigns of the Parties.

8.3           Cooperation Under Related Dedication Agreements. The Parties expressly acknowledge that this Agreement is one of several agreements executed contemporaneously herewith by Producer, Gatherer, or an Affiliate of Gatherer pertaining to the gathering or transportation of Crude and water, and the disposal of water from the same Leases and Wells .and covering the same Area of Dedication (the "Related Dedication Agreements "), with certain facilities to be located, and services to be provided, under this Agreement in proximity to those covered under the Related Dedication Agreements. The cooperation and performance by the Parties and their respective Affiliates of all of the obligations under this Agreement and each of the Related Dedication Agreements is essential for the Parties to receive the full benefit of their bargain under this Agreement and the Related Dedication Agreements. Subject to Force Majeure and any other applicable provisions under this Agreement or any Related Dedication Agreement, Gatherer and each Affiliate of Gatherer which is a party to a Related Dedication Agreement, shall construct, install and put into service the Initial System, pursuant to this Agreement, and the corresponding Initial Systems for Crude transportation and water gathering as described in the Related Dedication Agreements, in each case, in their entirety, as to all of the Initial and Infill Receipt Points together with any future expansions beyond the Initial System undertaken pursuant to this Agreement and under the corresponding provisions of the Related Dedication Agreements.

8.4           Entirety; Amendment. Subject to Section 8.3, this Agreement, together with the Exhibits attached hereto, constitutes the entire agreement and understanding between the Parties hereto and supersedesand renders null and void and of no further force and effect any prior proposals, understandings, negotiations or agreements between the Parties relating to the subject matter hereof, and all amendments and letter agreements in any way relating thereto. No provision of this Agreement may be changed, modified, waived or discharged orally, and no change, modification, waiver or amendment of any provision will be effective except by written instrument executed by the Parties.

8.5           Severability. Should any part of this Agreement be found to be void, unenforceable or be required to be modified by a court or governmental authority, then only that part of this Agreement shall be voided, unenforceable, or modified accordingly. The remainder of this Agreement shall remain in force and unmodified, subject to Section 7 of the GT&C.

8.6           Additional Gas Services; Area of Interest. In the event Producer desires to construct, install, operate or perform gas delivery, gas quality enhancement, gas lift or re-injection, compression or other field services or Producer desires gas gathering services in areas of McKenzie County south of Township 150, Billings County, or Stark County, North Dakota ("Area of Interest ") (such additional types of locations or desired services collectively "Additional Gas Services"), Producer shall give notice to Gatherer regarding such Additional Gas Services before soliciting such Additional Gas Services or entering into any binding agreements with any third parties to perform such Additional Gas Services. The selection of Gatherer or any third party to perform such Additional Gas Services shall be in the sole discretion of Producer, and the performance of such Additional Gas Services shall be governed by a separate agreement containing mutually agreeable terms and conditions.

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8.7           Audit Rights.

i.          Except for Actual Construct Costs for which a process of disclosure and agreement is provided within Section 1(b) of the GT&C and Initial System Costs which are further addressed in Exhibit "E", upon ten (10) days prior written notice, either Party shall have the right, at reasonable times during normal business hours, but no more frequently than once each calendar year, at its own expense, to examine the books and records of the other Party to the extent necessary to audit and verify the accuracy of any statement, charge, or computation made under or pursuant to this Agreement. All statements, allocations, measurement, and payments made in any Accounting Period prior to the twenty-four (24) Month period preceding the Month in which notice of audit is given by the auditing Party shall be conclusively deemed to be true and correct and the scope of such audit shall be limited to statements, allocations, measurements and payments made during such twenty-four (24) Month period.

ii.         The auditing Party shall have ninety (90) days after commencement of the audit in which to submit a written claim, with supporting detail, for proposed adjustments. Ifthe auditing Party fails to submit a written report to the audited Party within the ninety (90) day period, then all statements, charges and computations made under or pursuant to this Agreement that were within the audit period shall be deemed to be appropriate and accurate. Upon receipt of an audit report, the audited Party shall have ninety (90) days to make all recommended adjustments, or to notify the auditing Party that it does not agree and its basis for disagreement. Any unresolved disagreements shall be resolved pursuant to Section 11 of the GT&C.

8.8           Amendment and Restatem ent of Original Agreement. Upon execution of this Agreement by Gatherer and Producer, this Agreement shall amend, restate, supersede and replace the Original Agreement, including any amendments thereto, in its entirety and for all purposes, effective as of the Effective Date.

8.9           Governing Law: Venue. TIDS AGREEMENT SHALL BE CONSTRUED IN ACCORDANCE WITH AND GOVERNED BY THE LAWS OF THE STATE OF NORTH DAKOTA WITHOUT REGARD TO PRINCIPLES OF CONFLICTS OF LAWS. EXCLUSIVE VENUE FOR ANY SUIT, ACTION OR PROCEEDING BROUGHT BY EITHER PARTY IN CONNECTION WITH THIS AGREEMENT OR ARISING OUT OF THE EFFECTIVE TERMS OR CONDITIONS HEREOF SHALL BE IN THE CITY AND COUNTY OF DENVER, COLORADO .

8.10         Counterparts. This Agreement may be executed in multiple counterparts, each of which shall constitute an original and all of which, when construed together, shall constitute one and the same instrument.

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8.11     Ratification . Emerald WB LLC hereby ratifies, confirms and approves the Agreement in all respects and adopts it as Emerald WB LLC's act and deed to the same ex.tent as if the Agreement had been executed by Emerald WB LLC on the date of its original execution, effective as of the Effective Date.

THE PARTIES HERETO have executed this Agreement effective as of the Day and year first above written.

GATHERER
DAKOTA MIDSTREAM, LLC
By:	/s/ Tim Reynolds
Name: Tim Reynolds
Title: Founding Partner
Date: May 26, 2015
PRODUCER
EMERALD OIL, INC.
By:	/s/ McAndrew Rudisill
Name: McAndrew Rudisill
Title: Chief Executive Officer and President
Date: May 26, 2015
EMERALD WB LLC
By:	/s/ McAndrew Rudisill
Name: McAndrew Rudisill
Title: President
Date: May 26, 2015

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EX-10.6

Exhibit 10.6

AMENDED AND RESTATED WATER DEDICATION AND GATHERING AGREEMENT

BETWEEN

DAKOTA FLUID SOLUTIONS LLC, F/K/A MESA OIL SERVICES, LLC

AND

EMERALD OIL, INC. & EMERALD WB LLC

AMENDED AND RESTATED WATER DEDICATION AND GATHERING AGREEMENT

THIS AMENDED AND RESTATED WATER DEDICATION AND GATHERING AGREEMENT ("Agreement") is entered into on May 26, 2015, but effective as of the 1st day of July, 2014 (the "Effective Date") by and between DAKOTA FLUID SOLUTIONS LLC, formerly known as MESA OIL SERVICES, LLC ("Gatherer"), and EMERALD OIL, INC. and EMERALD WB LLC (collectively, "Producer"). The term "Producer" shall also include any other Affiliates of Emerald Oil, Inc. or Emerald WB LLC that own or control leasehold interests or Water from leasehold interests located within the Area of Dedication at any time while this Agreement remains in effect. Producer and Gatherer are sometimes referred to herein individually as a "Party" and collectively as the "Parties".

RECITALS

A. Producer is the operator of certain oil and gas leases, wells, and/or lands within the area described in Exhibit "A" attached hereto and by reference made a part hereof (the "Area of Dedication "), and may acquire additional interests in oil and gas leases and/or lands within the Area of Dedication during the term of this Agreement (such current and future interests are referred to as the "Leases").

B. Producer desires to have Gatherer receive, gather and deliver all the Water, as defined in Exhibit "C" of this Agreement, produced from the Wells and Leases within the Area of Dedication ("Producer's Water").

C. The Parties have previously entered into that certain Disposal Well Services Agreement ("Original SWD Agreement ") dated July 30, 2012, for the disposal of Producer' s Water in the Sanders and Spackler Salt Water Disposal Wells, described more specifically in Exhibit "B" and concurrent with entering into this Agreement, the Parties desire to supersede and replace that Original SWD Agreement to provide for gathering of Producer's Water by Gatherer's Water System, as further described herein, and delivery of Producer's Water for disposal at the Sanders and Spackler Salt Water Disposal Wells and/or any additional salt water disposal wells hereafter operated by Gatherer and/or any other salt water disposal systems in which Gatherer arranges for the connection to and disposal in (collectively, the "SWD Wells").

D. Gatherer desires to receive Producer's Water at the Receipt Points and deliver Producer's Water at the Delivery Points (as such terms are defined herein), utilizing the facilities constructed, owned and operated by Gatherer.

E. The Parties entered into that certain Water Dedication and Gathering Agreement dated effective July l, 2014, as amended by that certain Amendment No. 1 dated effective November 19, 2014 (the "Original Agreement' ) and desire now to amend and restate the Original Agreement in its entirety, effective as of July 1, 2014, to address and incorporate additional facilities to be constructed and operated by Gatherer at the request of Producer to receive Producer's Water, from the same Initial System DSUs as identified in Exhibit "B-1" herein at certain new "Infill Receipt Points" in exchange for additional consideration to Gatherer.

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F. The Parties also desire now to name and include Emerald WB LLC as a Producer Party to this Agreement and to have Emerald WB LLC ratify the Original Agreement.

Now therefore, in consideration of the mutual covenants and agreements contained in this Agreement, the Parties agree as follows:

ARTICLE I

REPRESENTATIONS & COMMITMENTS OF PRODUCER

1.1         Producer's Representations. Producer represents and warrants to Gatherer, its successors and assigns, that Producer is the operator of or has the right to operate the Wells listed on Exhibit "B-2" and that Producer has constructed, intends to construct, or shall cause to be constructed, the facilities necessary, if any, to enable Producer to deliver to Gatherer at the Receipt Points all of Producer's Water in accordance with the terms and provisions of this Agreement, as well as any other facilities committed to by Producer under this Agreement.

1.2         Dedication. Producer hereby dedicates and/or commits to the performance of this Agreement and all of the terms and conditions herein for the Primary Term, as defined herein, as a covenant running with the land all of Producer's Water produced from the Wells. Producer covenants to deliver all of Producer's Water to Gatherer at the Receipt Points without other disposition except as otherwise provided in this Agreement.

1.3         Producer's Reservations. Producer, as a reasonable and prudent operator, hereby reserves the right to use Water for Producer's Well operations and to operate the Wells free from any control by Gatherer in such manner as Producer, in Producer's sole discretion, may deem advisable, including without limitation the right to enter into farmouts of any oil and gas lease subject to this Agreement, to abandon any Well and surrender any lease. Producer shall not be required to produce any Well or Wells in any manner which in its sole judgment and discretion would not constitute good operating practice, nor shall Producer be obligated to drill additional Wells or to deepen, repair or rework any existing Wells.

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1.4         Release Rights.

a.           Alternate Transport In Lieu of Temporary Release. The remedies provided in this Section 1.4(a) shall only apply with respect to the Infill Receipt Points beginning on the date that Gatherer provides notice to Producer that the Infill Receipt Points are ready to accept Producer's Water, and prior to such date Producer is responsible for transport of Producer's Water from wells located at the Infill Receipt Points at Producer's sole cost and expense. Producer shall bear all trucking costs prior to the Commitment Period. Notwithstanding any other provision herein, during any period after the Initial System In-Service Date, as defined in Section 2.4, in the event (i) Gatherer is unable or fails to accept delivery of any of Producer's Water into Gatherer's Water System for any reason, including Force Majeure, (ii) the Barrels of Producer's Water that Gatherer is unable or fails to accept delivery of would not exceed of the operational capacity of Gatherer's Water System, considered with respect to Gatherer 's Water System as a whole or the applicable Receipt Point, and (iii) there exists no uncured material breach of this Agreement on the part of Producer which causes Gatherer's inability or failure to accept delivery of Producer 's Water, then Gatherer remains obligated under Section 1.5 below to receive Producer's Water at the Receipt Points and truck or otherwise transport, to the SWD Wells or other proper disposal locations at Gatherer's option, all such Barrels of Producer's Water which Gatherer has failed to accept into Gatherer's Water System ("Alternate Transport Barrels"). Gatherer shall bear all costs to truck or otherwise transport the Alternate Transport Barrels from the Receipt Point to the SWD Wells or other proper disposal location. Trucking or other alternative transport by Gatherer shall be deemed a release from this Agreement of Producer's dedication obligation under this Agreement only to the limited extent it is a release from any obligation of Producer to deliver or Gatherer to receive and gather Producer's Water specifically onto the Water Gathering System for gathering, with all other terms and conditions of this Agreement, including but not limited to, Producer's obligation to pay the Base Fees attributable to the Alternate Transport Barrels, remaining in full force and effect. The Alternate Transport obligations set forth herein shall only apply to the Alternate Transport Barrels, and further do not extend to Producer's separate rights and obligations under the New SWD Agreement. Furthermore, during any Accounting Period in which an Alternate Transport Release occurs, the Alternate Transport Barrels shall be deemed Delivered Barrels for purposes of calculating the Shortfall Payment for such Accounting Period.

b.           Temporary Release. Notwithstanding any other provision herein, during any period after the Initial System In-Service Date, as defined in Section 2.4, in the event (i) Gatherer is unable or fails to accept delivery of any of Producer's Water into Gatherer's Water System for any reason, including Force Majeure, (ii) the Barrels of Producer's Water that Gatherer is unable or fails to accept delivery of would exceed the operational capacity of Gatherer's Water System, considered with respect to Gatherer's Water System as a whole or the applicable Receipt Point, and (iii) Gatherer does not otherwise elect to truck such excess Barrels of Producer's Water in the same manner as set forth in Section l.4(a), notwithstanding the fact that the operational capacity of Gatherer's Water System is exceeded, then Producer shall be temporarily released from the dedication under this Agreement, and at Producer 's election, in its sole discretion, from the dedication under New SWD Agreement ("Temporary Release") , upon delivering written notice to Gatherer, and Gatherer's acknowledgement of receipt of such notice. Failure of Gatherer to respond (or accept delivery of the Excess Barrels of Producer's Water) within twenty-four (24) hours to a waiver request from Producer shall be deemed to be a confirmation by Gatherer of the lack of capacity on Gatherer's Water System. The Temporary Release of Producer 's Water shall only apply to those quantities of Producer's Water, which Gatherer has failed to accept at the Receipt Points as provided in this Section l .4(b) ("Temporary Released Barrels"). Producer shall be solely responsible for all costs and expenses associated with the trucking or other transport of the Temporary Released Barrels and the costs and expenses associated with the disposal of the Temporary Released Barrels, to the extent Producer elects not to dispose of such Barrels into the SWD Wells, and such costs and expenses are not subject to reimbursement by Gatherer. Furthermore, the Temporary Released Barrels shall be considered Delivered Barrels for purposes of calculating the Shortfall Payment for such Accounting Period.

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c.           Permanent Release. Except for the six (6) month period commencing as of the Initial System In-Service Date, and subject to Section 2.6 in the context of future expansion beyond the Initial System, as applicable, in the event Gatherer has not accepted delivery of the entire quantity of Producer's Water made available by Producer at the Receipt Points for any reason whatsoever , including, without limitation, Force Majeure or necessary maintenance affecting Gatherer's Water System or the SWD Wells, for a continuous period of ninety (90) consecutive days, or one hundred and twenty (120) days within a one hundred eighty (180) day period, Gatherer shall have the obligation to seek and put into place alternative, reasonably equivalent, gathering or trucking arrangements, as well as disposal arrangements if necessary, for Producer's Water, subject to the same Water Gathering Fees and other terms and conditions of this Agreement, then either Party shall have the right to have the portion of Producer's Water affected thereby permanently released from this Agreement (a "Permanent Release"), and at Producer 's election, in its sole discretion, from the dedication under New SWD Agreement, by delivering written notice thereof to the other Party within thirty (30) days after the expiration of any such ninety (90) consecutive day period, or one hundred eighty (180) day period as applicable. Furthermore, the applicable Minimum Barrels for each Accounting Period remaining during the Commitment Period shall be reduced by the Barrels produced from the Leases and Wells subject to Permanent Release for each such Accounting Period (the "Permanently Released Barrels").

1.5         Further Arrangements. Gatherer commits that, during the Primary Term and any Extended Term of this Agreement, as defined in Section 7.1 below, it will maintain all necessary arrangements to provide for the further transportation, disposition, and disposal of Producer's Water consistent with Producer's required communications under Section 2.8 herein and subject to Force Majeure, following Gatherer's receipt of Producer's Water at the Receipt Points. Gatherer will use reasonable efforts to enter into trucking arrangements as needed at the Receipt Points or Delivery Points to facilitate the further transport, disposition and disposal of Producer's Water. For all Barrels of Producer's Water received by Gatherer at the Receipt Points hereunder, Producer shall pay all Water Gathering Fees otherwise due on those Barrels under this Agreement as if received into Gatherer's Water System as well as fees for such Barrels arising under the New SWD Agreement whether or not such Barrels are in fact gathered on the Gatherer's Water System under this Agreement, and Gatherer shall bear one hundred percent (100%) of the costs of any trucking fees or similar charges to transport, redeliver, and dispose of Producer's Water by alternative transportation means or at alternative disposal facilities.

1.6         Memorandum of Agreement. Upon execution of this Agreement, the Parties shall execute a new Memorandum of Dedication of Water Production under this Agreement, in substantially the form attached as Exhibit "D" including a legal description of the Area of Dedication that corrects and replaces the Memorandum of the Original Agreement by expressly including Emerald WB LLC as a dedicating party, together with any of Producer's other Affiliates which own or control leasehold interests or Water from leasehold interests located within the Area of Dedication, during the Primary Term or Extended Term of this Agreement. Such Memorandum shall be placed of record in each county in which the Wells are located with Producer to bear all costs. In the event of any Permanent Release or termination of this Agreement, in whole or in part, the Parties shall execute appropriate instruments to be placed of record in each county in which the Wells are located, providing notice of the amended Area of Dedication or termination of this Agreement.

1.7        Superseding and Replacement of SWD Agreement. Producer acknowledges and agrees that as a condition precedent to Producer's rights and Gatherer's obligations under this Agreement, the Original SWD Agreement shall be superseded and replaced by a new agreement (the "New SWD Agreement "), entered into on or before the Effective Date of this Agreement, as needed to accomplish the purpose of this Agreement, and Producer shall execute the same. To the extent of a conflict between the terms of this Agreement and the terms of the New SWD Agreement, the terms of this Agreement shall control.

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ARTICLE II

FACILITIES

2.1         Gatherer's Water System. Gatherer will construct, operate and maintain a Water gathering system comprised of the Initial System, and any Future Receipt Points, Future Delivery Points, and expansions of Gatherer's Water System constructed pursuant to Section 2.6 (collectively "Gatherer's Water System") located as necessary to enable Gatherer to receive and gather Producer's Water from the Area of Dedication at the Receipt Points and deliver Producer's Water to the Delivery Points. Gatherer shall construct and operate Gatherer's Water System in a workman-like manner and in accordance with good oilfield practices, and in compliance with any applicable permits and licenses and all applicable rules, laws and regulations. Gatherer's Water System will consist of:

i.            "Receipt Points" shall be at the inlet of Gatherer's Metering Facilities located at the locations described on Exhibit "B" as RP1 through RP8 (the "Initial Receipt Points") and as RP10 through RP14 and RP16 (the "Infill Receipt Points"),together with any additional locations installed as part of any expansion of Gatherer's Water System beyond the Initial System (the "Future Receipt Points").

ii.           "Delivery Points" shall be the inlet flange of the disposal station piping of the SWD Wells located at the locations described on Exhibit "B" (the "Initial Delivery Points"), together with any additional locations installed as part of any expansion of Gatherer's Water System beyond the Initial System (the "Future Delivery Points").

iii.          "Gatherer 's Receipt Point Facilities" means all facilities owned, operated, and maintained by Gatherer at the Receipt Points to facilitate the connection of the Producer's Water Facilities (as defined below) with the Gathering Lines.

iv.          "Metering Facilities" including suitable custody transfer measurement equipment located at or near the Receipt Points to measure the Barrels of Producer's Water received by Gatherer.

v.           "Gathering Lines" means water gathering pipelines extending from the Receipt Points to the Delivery Points, together with appurtenances thereto, with sufficient capacity across Gatherer's Water System to receive, gather and deliver Producer's Capacity, as defined in Section 3.1, attributable to such Receipt Point.

vi.          “Gatherer's Delivery Point Facilities” means all facilities owned, operated and maintained by Gatherer at the Delivery Points, but not including disposal facilities covered under the New SWD Agreement.

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2.2         Rights-of-Way. At the time of executing this Agreement, Producer has completed its acquisition of rights-of-way (the "ROW" or "ROWs") from certain landowners within the Area of Dedication ("Landowners") authorizing the construction, installation and operation of multiple pipelines within the same right-of-way corridor. Producer shall be able to assign the ROWs in part to Gatherer, so as to grant Gatherer the right to install a single Water gathering line and related facilities in the corridor of the ROW in connection with the construction, installation, and operation of the Initial System. Due to Producer's existing relationship with the Landowners, and in an effort to maximize efficiency, Producer will continue to interface directly with the Landowners until such time as the ROWs have been partially assigned to Gatherer, except as described below. Producer has tendered compensation to the respective Landowner and has recorded the respective ROW with the McKenzie County Clerk and Recorder. With respect to each ROW, until such time as Producer assigns the ROWs to Gatherer, Producer shall indemnify and hold harmless Gatherer, its Affiliates, and their respective employees, officers, directors, contractors and subcontractors (collectively, "Gatherer Indemnified Parties")from and against any and all trespass claims or claims arising out of the invalidity of any ROW brought by third party landowners arising from Gatherer's ingress to, egress from, entry upon, and use of such ROWs for survey, construction, installation and operation of the Gatherer's Water System except to the extent arising from the gross negligence or willful misconduct of Gatherer Indemnified Parties.

Producer shall use commercially reasonable efforts to obtain any third party consents required to assign its ROWs to Gatherer (each a "Consent to Assign ") . In the event Producer, despite commercially reasonable efforts, is unable to obtain any Consent to Assign Producer shall continue to hold such ROW for the benefit of Gatherer until such time as the Consent to Assign is obtained. Concurrently with the execution of this Agreement, Producer shall partially assign the ROWs to Gatherer, pursuant to the form of assignment attached hereto as Exhibit "G'', and within thirty (30) days of receipt of detailed invoice and reasonably requested supporting documentation, Gatherer shall pay Producer twenty percent (20%) of the actual and direct costs incurred in obtaining the ROWs (based on five (5) pipelines allowed within a ROW and adjusted up or down for fewer or more pipelines properly located within a single ROW)

However, if Gatherer determines that any ROW is unnecessary for the Initial System or is insufficient, lacking, or otherwise defective, such that Gatherer in its reasonable discretion must acquire a new right-of-way in lieu thereof, such ROW shall not be assigned to Gatherer and Gatherer shall not pay any portion of the costs associated with such ROW.

Gatherer may proceed to interface with and acquire the real property interests it requires, including additional rights-of-way or amendments to ROWs to serve the Infill Receipt Points directly from the Landowners or other owners of such interests ("Gatherer ROWs"). In the event that Gatherer, despite commercially reasonable efforts, is unable to obtain any right-of-way deemed necessary for Gatherer in its reasonable discretion to construct and install the portions of the Initial System serving the Infill Receipt Points prior to May 31, 2015 (an "OutstandingROW'), Gatherer may proceed with re-routing the course of the affected portion of the Initial System and acquire additional Gatherer ROWs to circumvent any uncooperative third party landowners with Gatherer to bear such Outstanding ROW costs and re-routing costs in the aggregate up to Eighty-Three Thousand Three Hundred and Thirty Three dollars ($83,333), which costs shall not be included in the Actual Construct Costs. In the event the Outstanding ROW costs are anticipated to exceed $83,333 the Parties shall promptly meet to develop a mutually agreeable plan to complete acquisition of Outstanding ROW. The Initial System Target In-Service Date shall be extended, as an Excused Delay as defined in Section 2.4 below, by the number of days, if any, that the construction and installation of the Initial System is delayed in order to acquire the Outstanding ROW or agree on a course of action, or otherwise due directly to the Outstanding ROW.

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2.3         Producer's Water Facilities and Construction. Producer at its own expense will construct, operate and maintain all facilities upstream of the Receipt Points as identified in Exhibits "B" and "B-2" necessary to enable Producer to deliver all of Producer's Water to Gatherer at the Receipt Points as identified in Exhibits "B" and "B-2" in a workman like manner and in accordance with good oil field practices, and in compliance with any applicable permits and licenses and all applicable rules, laws, and regulations. "Producer's Water Facilities" will consist of the facilities listed below. Producer shall provide the following facilities:

i.            "Piping" connecting Producer's Wells to the Receipt Points.

ii.           "Pumps" located upstream of each Receipt Point sufficient to effectuate the flow of Producer's Water into and on Gatherer's Water System and to allow Gatherer's Water System to operate at maximum capacity.

iii.          "Storage" or tankage facilities upstream of each Receipt Points having at least 24 hours of storage capacity for Producer's Water to be delivered to each Receipt Point.

iv.         "Utilities" including electrical or .other power at the Receipt Points furnished to Gatherer and sufficient for Gatherer's Receipt Point Facilities.

v.           "Filtering' for Water as set forth in Exhibit "F".

2.4         Initial System. The "Initial System" will consist of the initial facilities of Gatherer, described generally above and on Exhibit "B", as necessary to connect the Initial Receipt Points and Infill Receipt Points with the Initial Delivery Points, also described on Exhibit "B". The Parties have agreed upon the configuration, design and construction of Gatherer's Water System and have deemed the Initial System as sufficient to serve all of Producer's Minimum Barrels commitment stated in Exhibit "E" and that the Initial System is sufficient to serve all of Producer's anticipated Barrels of Producer's Water from the Wells identified on Exhibit "B-2" (collectively, the "Initial System Wells") at the Initial Receipt Point or Infill Receipt Point listed in the column "Gatherer Receipt Point Construction Responsibilities" next to each such Well.

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Subject to events of Force Majeure, severe winter weather, frost laws, road restrictions and other requirements or delays imposed by government agencies including without limitation delays in issuing ROWs on federal lands needed for the portion of Gatherer's Water System serving the Infill Receipt Points, whether or not within the scope of Force Majeure, that would make the diligent pursuit of similar construction or installation operations unreasonable for a reasonably prudent McKenzie County North Dakota gatherer faced with similar conditions (whether one or more, "Excused Delays "), Gatherer shall diligently construct, install and complete (y) the portion of Gatherer's Water System serving the Initial Receipt Points as described on Exhibit "B" and Exhibit "B-2" on or before June 1, 2015 (the "Start-Up Target Date") and (z) all of the Initial System including the Initial and Infill Receipt Points on or before August 31, 2015, as extended by the number of Days equal to any Excused Delay event (the "initial System Target In-Service Date ") . The Parties each agree that their respective obligations to meet the Start-Up Target Date are on a reasonable commercial efforts basis with no credits or penalties applicable to either Party for non-achievement. Producer acknowledges and agrees that any receipt, gathering and delivery of Water by Producer prior to the Initial System In-Service Date shall incur the applicable Water Gathering Fees and shall be provided on an interruptible basis at Gatherer's sole discretion as Gatherer may be completing the installation and construction of its Water Gathering System and may also need to undertake calibration and other activities to achieve the Initial System In-Service Date during that period, provided however, that Gatherer shall notify Producer twenty four (24) hours or as soon as practicable prior to any activities of Gatherer that may reasonably be expected to cause an interruption or otherwise prevent Gatherer from receiving Water from any Receipt Point from which Gatherer has previously accepted Water, and Gatherer shall keep Producer fully informed of the progress of such activities and any anticipated resumption of service from such Receipt Point(s). The date on which Gatherer has completed the construction and installation of the Initial System, in its entirety so as to be capable of receiving Producer's Water from all of the Initial Receipt Points and Infill Receipt Points identified on Exhibits "B" and "B-2" shall be the "Initial System In-Service Date". For avoidance of doubt, such completion by Gatherer shall be a deemed achievement of the Initial System In-Service Date notwithstanding the Initial System's partial or complete inability to accept and flow Water on the Initial System when such inability arises solely from Producer's delay or failure to complete its responsibilities and obligations under this Agreement, as extended by Force Majeure or in the case of delay or failure to complete re-run piping if caused by frost laws imposed by government agencies.

i.            In the event, subject to Force Majeure or Excused Delay, Gatherer fails to complete its construction of the Initial System, in its entirety per Section 2.4, Exhibit "B" and Exhibit "B-2", on or before the Initial System Target In-Service Date, and Producer has completed all facilities upstream of the Initial and Infill Receipt Points per Section 2.3, Exhibit "B" and Exhibit "B-2", and is otherwise ready, willing and able to deliver Producer's Water to that portion of the Initial System that is not completed, the following shall occur:

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a.           the applicable Minimum Barrels for each Accounting Period, or portion thereof, between the Initial System Target In-Service Date and the Initial System In-Service Date, shall be reduced by the daily Barrels of Producer's Water produced from the Initial System In-Service Date Wells that would have been transported on the Initial System had such System been in operation for each such Accounting Period (the "Gatherer's Initial System Delay Pre-Inservice Barrels"); and

b.          Producer shall receive a credit against the Water Gathering Fees owed by Producer in that Accounting Period (or if none are owed in that Accounting Period, beginning in the next occurring Accounting Period in which Water Gathering Fees are owed by Producer and continuing for each successive Accounting Period until the credit is used in full, with the credit amount equal to the Base Fee for the Gatherer's Initial System Delay Pre-Inservice Barrels, up to a maximum total credit of Two Million dollars ($2,000,000) for all Gatherer's Initial System Delay Pre-Inservice Barrels under this Agreement together with all "Gatherer's Initial System Delay Pre-Inservice Barrels [or Volumes]" under the Related Dedication Agreements described in Section 8.3 herein ("Initial System Pre-Inservice Credit") .

ii.           In the event Gatherer has completed its construction of the Initial System, in its entirety per Section 2.4, Exhibit "B'' and Exhibit "B-2" on or before the Initial System Target In-Service Date, but subject to Force Majeure or in the case of delay or failure to complete re-run piping if caused by frost laws imposed by government agencies, Producer has failed to complete all facilities upstream of the Initial and Infill Receipt Points per Section 2.3, Exhibit "B" and Exhibit "B-2", and Gatherer is otherwise ready, willing and able to gather Producer's Water on that portion of the Initial System, then the following shall occur:

a.           the applicable Minimum Barrels for each Accounting Period, or portion thereof, between the Initial System Target In-Service Date and the Initial System In-Service Date, shall be reduced by the Barrels of Producer's Water produced from the Initial System In-Service Date Wells that would have been transported on the Initial System had Producer's Water Facilities been in operation for each Accounting Period (the "Producer's Initial System Delay Pre Inservice Barrels").

b.           Producer shall pay Gatherer an amount equal to the per Barrel Base Fee for the Producer's Initial System Delay Pre-Inservice Barrels beginning in the first Accounting Period following the Initial System In-Service Date and continuing for each successive Accounting Period until the payment is satisfied in full, up to a maximum of Two Million dollars ($2,000,000), for all Producer's Initial System Delay Pre-Inservice Barrels under this Agreement together with all "Producer's Initial System Delay Inservice Barrels [or Volumes]" as defined under the Related Dedication Agreements described in Section 8.3 herein ("Initial System Pre-Inservice Fee").

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iii.          In addition to Producer's remedies under Section 2.4(i), in the event Gatherer fails to complete its construction of the Initial System, in its entirety per Section 2.4, Exhibit "B" and Exhibit "B-2", on or before the date that is sixty (60) Days after the Initial System Target In-Service Date, and Producer has completed all facilities upstream of the Initial and Infill Receipt Points per Section 2.3, Exhibit "B" and Exhibit "B-2" and is otherwise ready, willing and able to deliver Producer's Water to that portion of the Initial System that is not completed, Producer shall have the option, exercisable in its sole discretion, to elect by written notice to Gatherer to construct and install the remainder of the Initial System, at Producer's sole cost and expense, whereupon Producer shall not owe any Base Fees for any of Producer's Water delivered to the Initial and Infill Receipt Points or flowing through that portion of the Initial System constructed and installed by Producer, until such time as the amount of Base Fees otherwise attributable to such Water, but retained by Producer, is equal to one hundred and ten percent (110%) of the total of Actual Construct Costs incurred by Producer to complete the construction and installation of the remainder of the Initial System.

iv.          Gatherer shall keep Producer reasonably informed of the progress on the construction and installation of the Initial System, and any Excused Delays in connection therewith. Producer shall have the right to have its representative present during any onsite construction or installation operations of the Initial System.

2.5         Disposal Facilities. All facilities downstream of the Delivery Points, including the SWD Wells, as necessary to enable the disposal of all of Producer's Water in the SWD Wells shall be addressed under the New SWD Agreement.

2.6         Future Expansion Beyond the Initial System. After installation of the Initial System, Gatherer will install and connect such Future Receipt Points, Future Delivery Points, and expansions of Gatherer's Water System, including but not limited to, installing additional or "looped" gathering lines or a larger diameter pipe that Gatherer in its sole judgment determines are necessary or desirable to gather Producer's Water dedicated under this Agreement from subsequent completed Wells drilled or acquired by Producer within the Area of Dedication as set forth in this Section 2.6. For avoidance of doubt, any expansion of Gatherer's Water System to serve Producer's Wells located outside the Area of Dedication is not contemplated by or covered under the scope of this Agreement. The Parties agree that Gatherer will own and operate any and all future expansions to Gatherer's Water System including any Producer Built Gathering Facility, as defined herein.

i.            In addition to providing Gatherer with annual drilling plans and quarterly updates to those plans under Section 2.8 below, Producer shall give Gatherer written notice (a "Connection Notice ") one hundred twenty (120) to ninety (90) Days prior to the completion of any new Well located within the Area of Dedication but outside of the Initial System DSUs, or within ten (10) days after acquiring any such completed Well, specifying: the Well name, Well location; the location of the nearest Receipt Point or proposed Future Receipt Point, as applicable, for such Well; drilling, completions and anticipated recompletion details; the minimum anticipated initial and annual Barrels of Producer's Water from such Well together with the anticipated available Barrels of Producer 's Water from the drilling spacing unit ("DSU') in which the Well is located as may be requested by Gatherer; and if a Distant Expansion under subsection (iv) below applies, also specifying up to four (4) DSUs that are each directly adjacent to or cornering the DSU (the "Contiguous DSUs") of the Distant Well (defined below) for possible Permanent Release at Producer's sole discretion under subsection (iv)(a) below if (iv)(a) applies and the anticipated available Barrels of Producer's Water from the four (4) Contiguous DSUs as may be requested by Gatherer (the anticipated Barrels from the DSU of the Distant Well and the four (4) Contiguous DSU Barrels if requested, are collectively the "Connection Barrels") . Concurrently with its Connection Notice under this Agreement, Producer shall provide Gatherer with the Connection Notices concerning the Well as required under the Related Dedication Agreements described in Section 8.3 of this Agreement. If a Well that is the subject of a Connection Notice is not completed within one hundred twenty (120) Days of the Connection Notice, following good faith discussions with Producer, Gatherer shall then have the option to deem the Connection Notice as invalid and of no further effect.

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ii.           In the event the Well, or the Future Receipt Point, if applicable, as identified in the Connection Notice requires less than or equal to a three (3) mile expansion of Gatherer 's Water System from an existing Receipt Point or Delivery Point, as Gatherer's Water System exists as of the date of the Connection Notice (a "Nearby Well"), Gatherer shall have the first option to construct, install and place into operation an expansion of Gatherer's Water System to connect to the Nearby Well at Gatherer's sole cost and expense, in exchange for Gatherer's ability to charge Producer an additional fee per Barrel for any Water from such Nearby Well or any other Well Producer flows through such expansion constructed by Gatherer, based on the sample calculation set forth in Exhibit "H," such that Gatherer has recouped Actual Construct Costs incurred by Gatherer to construct the expansion plus incremental operating expenses and capital expenditures needed to modify or upsize the Initial System or a prior expansion of the Initial System to accommodate the Connection Barrels, over a five (5) year period and receive a seven and a half percent (7.5%) internal rate of return ("IRR" as calculated by the Microsoft Excel IRR function financial formula) and trued up quarterly ("Expansion Fee"). For the avoidance of doubt the Expansion Fee shall be in addition to all other Water Gathering Fees due for the Connection Barrels and such Expansion Fee shall be reduced equitably if Gatherer, in its sole discretion, elects to construct and install an expansion of larger size or greater capacity than requested by Producer in its Connection Notice or required to serve Producer's Connection Barrels.

m.          Subject to Force Majeure and the condition that Producer has in fact completed such a Nearby Well, in the event Gatherer fails to timely construct, install and make available for operation on or before the later of ninety (90) days from receipt of the Connection Notice or the date the Well identified in the respective Connection Notice is completed, an expansion of Gatherer's Water System to connect the Connection Barrels from the Nearby Well, following good faith discussions with Gatherer, Producer shall have the option either to:

a.           Construct and install an expansion of Gatherer's Water System to connect to the Nearby Well, at Producer 's sole cost and expense, in exchange for Producer receiving a credit against any Base Fee component of the Water Gathering Fees otherwise owed Gatherer for any Water from such Nearby Well or any other Well flowing through such expansion constructed by Producer, until such time as the amount of the Base Fee component of the Water Gathering Fees otherwise attributable to such Water, but retained by Producer, is equal to the total of Actual Construct Costs incurred by Producer to construct the expansion based on the sample calculations set forth in Exhibit "H" such that Producer has recouped its Actual Construct Costs incurred by Producer to construct the expansion plus incremental operating expenses and capital expenditures needed to modify or upsize the Initial System or a prior expansion of the Initial System to accommodate the Connection Barrels, over a five (5) year period and receive a seven and a half percent (7.5%) IRR and trued up quarterly ("Expansion Credit”); or

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b.          Subject to Section l.4(c), obtain a Permanent Release from this Agreement of the Nearby Well and any of the Leases located within the same DSU as the Nearby Well but not located within an Initial System DSU.

iv.         In the event the Well, or the Future Receipt Point or Delivery Point, if applicable, as identified in the Connection Notice requires more than a three (3) mile expansion of Gatherer's Water System, as Gatherer's Water System exists as of the date of the Connection Notice ("Distant Well") or involves a connection of Gatherer's Water System with facilities of third parties not connected to Gatherer's Water System as of the date of the Connection Notice (one or both situations, a "Distant Expansion "), the Parties shall promptly pursue good faith negotiations of mutually agreeable terms and conditions of such expansion and strive to enter into a definitive separate agreement or written amendment setting forth a definitive agreement as to such Distant Expansion. In the event the Parties have not reached agreement on or before the later of ninety (90) days from receipt of the Connection Notice or the date the Well identified in the respective Connection Notice is completed, for the terms of such a Distant Expansion of Gatherer's Water System, following good faith discussions with Gatherer, Producer shall have the option to:

a.           Subject to Section 1.4(c), obtain a Permanent Release from this Agreement of any of the Leases located within the DSU of the Distant Well, and the four (4) Contiguous DSUs but only if such Leases are not located within an Initial System DSU.

v.           Gatherer shall keep Producer reasonably informed of the progress on the construction and installation of any expansion of Gatherer's Water System. Producer shall have the right to have its representative present during any onsite construction or installation operations of any expansion of Gatherer's Water System.

2.7         Construction or Expansion by Producer. In the event Producer elects to construct, install or expand any portion of Gatherer's Water System pursuant to an express right provided under this Agreement (a "Producer Built Gathering Facility "), the following shall apply:

i.            Each Producer Built Gathering Facility shall be constructed and installed by Producer according to the reasonable design and construction specifications of Gatherer. In constructing and installing the Producer Built Gathering Facility, Producer shall have the right to utilize any available water pipeline right-of-way or easement rights of Gatherer and any materials of Gatherer, at cost.

ii.           Upon completion of any Producer Built Gathering Facility, Producer shall assign such Producer Built Gathering Facility to Gatherer, at no charge to Gatherer, but expressly subject to the terms of this Agreement, whereupon it shall become part of Gatherer's Water System.

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m.          If Producer has incurred Actual Construct Costs pursuant to Section 2.6(iii)(a), once Producer has recouped all of such Costs pursuant to Section 2.6, Gatherer may begin to assess applicable Base Fee components of Water Gathering Fees for all Water delivered by Producer into or flowing through such Producer Built Gathering Facility. Gatherer may begin to assess all other components of the Water Gathering Fees for all Water delivered by Producer beginning upon the commencement of receipt into or flow through such Producer Built Gathering Facility.

iv.          For the avoidance of doubt, for purposes of determining whether Producer has delivered the Minimum Barrels in any Accounting Period pursuant to the terms and conditions set forth on Exhibit "E", any Water delivered during such Accounting Period for which Producer does not owe any Base Fee component of the Water Gathering Fees pursuant to its incurrence of Actual Construct Costs pursuant to Article 2 of this Agreement shall be included in the Delivered Barrels.

2.8         Producer's Anticipated Barrels. Upon the execution of this Agreement, and thereafter by October first (1st) of each calendar year, Producer shall communicate its drilling, completion and recompletion plans to Gatherer in writing, including locations, anticipated spud dates, together with anticipated Barrels to be delivered to Gatherer, for the next calendar year. Additionally, during Gatherer's construction of facilities to serve the Infill Receipt Points, Producer shall promptly notify Gatherer of any delay in its drilling and completion schedules for the Wells identified in Exhibit "B-2'', including without limitation delays in completion of any Wells on Exhibit "B-2" later than June 1, 2015. At all other times during the Primary Term or Extended Term, no later than the last day of each calendar quarter, Producer shall notify Gatherer in writing with reasonable detail of any changes or additions to its drilling plans for the succeeding twelve (12) Accounting Periods. In addition to providing Connection Notices, pursuant to Section 2.6(i), Producer shall provide updates to Gatherer, as needed, of specific drilling and completion plans and actual initial production dates.

2.9         Ownership of Facilities. Producer expressly does not by the terms of this Agreement, sell, transfer or assign unto Gatherer any title or interest whatsoever in the Wells or any pipe, lines or other equipment of any nature owned and used by Producer in the operation of Producer's Wells, Producer's Water Facilities, Wells, or Leases. Gatherer expressly does not by the terms of this Agreement, sell, transfer, or assign unto Producer any title or· interest whatsoever in Gatherer's Water System, or any pipelines, vehicles or other equipment of any nature owned and used by Gatherer in the operation of Gatherer's Water System or its performance of services under this Agreement.

ARTICLE III

GATHERING SERVICE

3.1         Producer's Capacity. Commencing on the Initial System In-Service Date, Gatherer shall make capacity available for Producer's Water on Gatherer's Water System up to 8000 Barrels/day at 250 Psig at each of the five individual Initial Receipt Points, RPI through RPS as described more specifically on Exhibit "B", and up to the operational capacity of other Receipt Points and the Gathering Lines, ("Producer's Capacity") for the benefit of Producer's Water, subject to Force Majeure. Initially Gatherer's Water System shall provide exclusive service for Producer's Water. From time to time during the Term and on a daily basis, any capacity available on Gatherer's Water System in excess of Producer's Capacity shall be available to Gatherer for Third Party Water, as defined below in Section 3.4 on such days. Producer 's Capacity shall be adjusted upward by additional Connection Barrels served by expansions of Gatherer's Water System pursuant to Section 2.6 of this Agreement to the extent the overall capacity of Gatherer 's Water System increases as a result of such expansion, and downward by Permanently Released Barrels pursuant to Section 1.4(c) of this Agreement.

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3.2         Gathering. Subject to the terms and conditions of this Agreement, and Producer's delivery of all of Producer's Water within the Area of Dedication to Gatherer at the Receipt Points, Gatherer shall receive at the Receipt Points, gather, and deliver Producer's Water at the Delivery Points. Delivery of Producer 's Water to a specific Delivery Point will be at Gatherer's sole option and discretion.

3.3         Uniform Delivery Rate. The Parties will strive to deliver Producer's Water at the Receipt and Delivery Points on a uniform basis consistently.

3.4         Third Party Service. Producer acknowledges and understands that over the term of this Agreement and after prior written notice received by Gatherer, Gatherer's Water System may also receive water delivered to Gatherer by other parties ("Third Party Water") , at all times subject to Producer's Capacity and such Third Party Water meeting the Water Quality Specifications set forth in the attached Exhibit "F" as such Water Quality Specifications may be updated from time to time by Gatherer upon thirty (30) days advance written notice to Producer.

3.5         Priority of Service. Producer's Water, up to Producer's Capacity, shall be accorded highest priority on Gatherer's Water System with respect to capacity allocations, interruptions, or curtailments. On a Receipt Point basis and subject to Producer fulfilling its operational obligations System under this Agreement including effectuating the delivery of Water into Gatherer's Water, Producer's Water will be the last Water curtailed from Gatherer's Water System in the event of an interruption or curtailment affecting specific Receipt Points rather than Gatherer's Water System as a whole, and all of Producer's Water affected by a particular Receipt Point will be treated in the same manner in the event an allocation is necessary. Gatherer agrees not to contract to provide, at any time, gathering service on Gatherer's Water System on a basis that has a priority higher than what Producer's Water is entitled to pursuant to this Section 3.5 and under this Agreement.

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ARTICLE IV

EXHIBITS

4.1         Exhibits. All Exhibits attached to this Agreement are incorporated into and made an integral part of this Agreement by reference including the General Terms and Conditions set forth in the attached Exhibit "C" (the "GT&C").

4.2         Order of Precedence. In the event of any conflict between the terms as set out in the body of this Agreement and those set out in the GT&C, the terms in the body of this Agreement shall control.

ARTICLE V

CONSIDERATION &

FEES

5.1         Fees. For all of Producer's Water received into Gatherer's Water System, Gatherer shall charge and Producer shall pay the applicable "Water Gathering Fees" and any "Shortfall Payment” described on Exhibit "E" based on the Barrels of Producer's Water received at the Receipt Points. The Water Gathering Fee does not encompass disposal fees which are incurred under the New SWD Agreement. If and as applicable under Section 2.4(ii)(b), Gatherer shall charge and Producer shall pay the Initial System Pre-Inservice Fee. If and as applicable under Section 2.6, Gatherer shall charge and Producer shall pay the Expansion Fee.

5.2         Annual Fee Adjustments. The Base Fee, Meter Fee, and any applicable Miscellaneous Fees, including without limitation the Expansion Fee, components of the Water Gathering Fees may be adjusted annually during the term of this Agreement, for the prospective calendar year, the first prospective calendar year being 2020, based on the percentage change in the annual average in the "Consumer Price Index for All Urban Consumers (CPI-U): U.S. city average -All items" which occurred in the preceding calendar year as published by the United States Department of Labor, Bureau of Labor Statistics for the previous calendar year, but shall never be less than the Base Fee or Meter Fee, as applicable, set forth in Exhibit "E".

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ARTICLE VI

NOTICES

6.1         Notice Process. All notices and communications required or permitted under this Agreement shall be in writing and shall be considered as having been given if delivered personally, or when received by mail, by electronic means (confirmed as received before 5 p.m. at the place of receipt), or by express courier, postage prepaid, by either Party to the other at the addresses given below. Routine communications, including monthly statements, shall be considered as duly delivered when mailed by ordinary mail or by electronic means.

6.2         Addresses for Notice. Unless changed upon written notice by either Party, the addresses for notice purposes are as follows:

TO: Emerald Oil, Inc. and/or Emerald WB LLC
1600 Broadway, Suite 1360

Denver, CO 80202

Phone: 303-595-5629

Contact: James Muchmore

TO: Dakota Fluid Solutions LLC
1600 Broadway, Suite 1330

Denver, CO 80202

Phone: 202-213-5998

Contact: Tim Reynolds

ARTICLE VII

TERM

7.1         Primary and Extended Terms. This Agreement shall commence as of the Effective Date and shall remain in full force and effect for a primary term of fifteen (15) years (the "Primary Term") and shall continue year to year thereafter until terminated by either Party (the "Extended Term") by providing written notice of termination to the other Party at least sixty (60) days prior to the expiration of the Primary Term, or any subsequent annual expiration date.

(10)       Uneconomic Operations. Subject to any Force Majeure event affecting Producer's obligations to deliver Water hereunder, in addition to all other rights of Gatherer under this Agreement, in the event the sum of actual direct costs (for the avoidance of doubt, excluding overhead, depreciation, amortization and capital expenditures) incurred by Gatherer to operate any portion of Gatherer's Water System (the "Uneconomic Segment” ) during any ninety (90) day period are in excess of the total net revenue attributable to the Uneconomic Segment (including all Water Gathering Fees paid by Producer or any third party attributable to the Uneconomic Segment) during such ninety (90) day period, Gatherer shall have the right to send written notice (an "Uneconomic Notice ") to Producer of its intent to terminate receipts of Producer's Water into the Uneconomic Segment unless the Water Gathering Fees owed by Producer for Producer's Water delivered to the Uneconomic Segment are increased such that Gatherer's total anticipated net revenue attributable to the Uneconomic Segment is projected to equal one hundred and ten percent (110%) of Gatherer's actual direct costs (for the avoidance of doubt, excluding overhead, depreciation, amortization and capital expenditures) incurred by Gatherer to operate the Uneconomic Segment. Any increased Gathering Fee shall be borne pro-rata by Producer and any third party shipper on the Uneconomic Segment according to the anticipated Barrels of Producer's Water to be delivered to or flowed through the Uneconomic Segment. Within ten days of Producer 's receipt of notice from Gatherer, Producer shall elect by written notice sent to Gatherer either to:

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a.           Accept the increased Water Gathering Fees, or portion thereof, effective as of the beginning of the next AccoW1ting Period, owed by Producer for Producer's Water delivered to the Uneconomic Segment, whereupon Gatherer shall not send another Uneconomic Notice pursuant to this Section 7.2 for at least ninety (90) days; or

b.           Elect to obtain a Permanent Release of Producer's Leases and Wells directly affected by the Uneconomic Segment, and at Producer's election, in its sole discretion, from the dedication W1der New SWD Agreement, by delivery of written notice to Gatherer insofar as it pertains to the Uneconomic Segment after one hW1dred-eighty (180) days of Producer's receipt of the Uneconomic Notice under this Section 7.2.

ARTICLE VIII

MISCELLANEOUS

8.1         Assignment. This Agreement, including, without limitation, any and all renewals, extensions, amendments and/or supplements hereto shall extend to and inure to the benefit of and be binding upon the Parties, and their respective successors and assigns, including any purchaser of Producer's interests in the leases that are dedicated W1der this Agreement or subsequent operator of the Wells and Producer's Water Facilities and upon any purchaser of Gatherer's Water System, or any part or interest therein which are subject to this Agreement; provided however, (i) this Agreement shall not be assigned by a Party without the prior written consent of the other Party, such consent shall not be unreasonably withheld, conditioned or delayed and (ii) no sale, assignment, conveyance, or other transfer (collectively, a "Transfer") of Producer's Leases, Wells or Producer's Water Facilities, or any part thereof or interest therein, or of any part of Gatherer's Water System, shall be made W11ess the transferee thereof shall assume and agree to be bound by this Agreement insofar as the same shall affect and relate to Producer' s Leases, the Wells, or Producer 's Water Facilities, Gatherer's Water System or interests so Transferred. Notwithstanding the conditions and restrictions set forth on assignment in this Section 8.1, each Party retains the right to freely assign this Agreement to an Affiliate within the first year following the Effective Date. Interests owned in the Area of Dedication by a transferee of any of Producer 's Leases or Wells that were owned prior to the effective date of such Transfer shall not become subject to this Agreement by virtue of such Transfer. It is further agreed, however, that nothing herein contained shall in any way prevent a Party hereto from pledging or mortgaging all or any part of its Leases, Wells, or Producer's Water Facilities if Producer, or Gatherer's Water System if Gatherer as security W1der any mortgage, deed of trust, or other similar lien, or from pledging this Agreement or any benefits accruing hereW1der to the Party making the pledge, without the assumption of obligations hereunder by the mortgagee, pledgee or other grantee W1der such instrument.

8.2         No Third Party Beneficiaries. Nothing in this Agreement, expressed or implied, confers any rights or remedies on any person or entity not a Party hereto other than successors and assigns of the Parties.

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8.3         Cooperation Under Related Dedication Agreements. The Parties expressly acknowledge that this Agreement is one of several agreements executed contemporaneously herewith by Producer, Gatherer, or an Affiliate of Gatherer pertaining to the gathering or transportation of crude and gas, and the disposal of water from the same Leases and Wells and covering the same Area of Dedication (the "Related Dedication Agreements "), with certain facilities to be located, and services to be provided, under this Agreement in proximity to those covered under the Related Dedication Agreements. The cooperation and performance by the Parties and their respective Affiliates of all of the obligations under this Agreement and each of the Related Dedication Agreements is essential for the Parties to receive the full benefit of their bargain under this Agreement and the Related Dedication Agreements. Subject to Force Majeure and any other applicable provisions under this Agreement or any Related Dedication Agreement, Gatherer and each Affiliate of Gatherer which is a party to a Related Dedication Agreement, shall construct, install and put into service the Initial System, pursuant to this Agreement, and the corresponding crude transportation system and gas gathering system under the Related Dedication Agreements, in each case, in their entirety, as to all of the Initial and Infill Receipt Points together with any future expansions beyond the Initial System undertaken pursuant to this Agreement and under the corresponding provisions of the Related Dedication Agreements.

8.4         Entirety; Amendment. Subject to Section 8.3, this Agreement together with the Exhibits attached hereto, constitutes the entire agreement and understanding between the Parties hereto and supersedes and renders null and void and of no further force and effect any prior proposals, understandings, negotiations or agreements between the Parties relating to the subject matter hereof, and all amendments and letter agreements in any way relating thereto. No provision of this Agreement may be changed, modified, waived or discharged orally, and no change, modification, waiver or amendment of any provision will be effective except by written instrument executed by the Parties.

8.5         Severability. Should any part of this Agreement be found to be void, unenforceable or be required to be modified by a court or governmental authority, then only that part of this Agreement shall be voided, unenforceable , or modified accordingly. The remainder of this Agreement shall remain in force and unmodified, subject to Section 6 of the GT&C.

8.6         Additional Water Services; Area of Interest. In the event Producer desires to construct, install, operate or perform water delivery, water management or water quality enhancement field services or Producer desires water gathering services in areas of McKenzie County south of Township 150, Billings County, or Stark County, North Dakota ("Area of Interest") (such additional types of locations or desired services collectively "Additional Water Services"), Producer shall give notice to Gatherer regarding such Additional Water Services, before soliciting such Additional Water Services or entering into any binding agreements with any third parties to perform such Additional Water Services. The selection of Gatherer or any third party to perform such Additional Water Services shall be in the sole discretion of Producer, and the performance of such Additional Water Services shall be at customary rates and governed by a separate agreement containing mutually agreeable terms and conditions.

8.7         Audit Rights.

a.           Except for Actual Construct Costs for which a process of disclosure and agreement is provided within Section 1(b) of the GT&C and Initial System Costs which are further addressed in Exhibit "E", upon ten (10) days prior written notice, either Party shall have the right, at reasonable times during normal business hours, but no more frequently than once each calendar year, at its own expense, to examine the books and records of the other Party to the extent necessary to audit and verify the accuracy of any statement, charge, or computation made under or pursuant to this Agreement. All statements, allocations, measurement, and payments made in any Accounting Period prior to the twenty-four (24) Month period preceding the Month in which notice of audit is given by the auditing Party shall be conclusively deemed to be true and correct and the scope of such audit shall be limited to statements, allocations, measurements and payments made during such twenty-four (24) Month period.

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b.           The auditing Party shall have ninety (90) days after commencement of the audit in which to submit a written claim, with supporting detail, for proposed adjustments. If the auditing Party fails to submit a written report to the audited Party within the ninety (90) day period, then all statements, charges and computations made under or pursuant to this Agreement that were within the audit period shall be deemed to be appropriate and accurate. Upon receipt of an audit report, the audited Party shall have ninety (90) days to make all recommended adjustments, or to notify the auditing Party that it does not agree and its basis for disagreement. Any unresolved disagreements shall be resolved pursuant to Section 10 of the GT&C.

8.8         Amendment and Restatement of Original Agreement. Upon execution of this Agreement by Gatherer and Producer, this Agreement shall amend, restate, supersede, and replace the Original Agreement, including any amendments thereto, in its entirety and for all purposes, effective as of the Effective Date.

8.9         Governing Law; Venue. THIS AGREEMENT SHALL BE CONSTRUED IN ACCORDANCE WITH AND GOVERNED BY THE LAWS OF THE STATE OF NORTH DAKOTA WITHOUT REGARD TO PRINCIPLES OF CONFLICTS OF LAWS. EXCLUSIVE VENUE FOR ANY SUIT, ACTION OR PROCEEDING BROUGHT BY EITHER PARTY IN CONNECTION WITH THIS AGREEMENT OR ARISING OUT OF THE TERMS OR CONDITIONS HEREOF SHALL BE IN THE CITY AND COUNTY OF DENVER, COLORADO.

8.10       Counterparts. This Agreement may be executed in multiple counterparts, each of which shall constitute an original and all of which, when construed together, shall constitute one and the same instrument.

8.11       Ratification. Emerald WB LLC hereby ratifies, confirms and approves the Agreement in all respects and adopts it as Emerald WB LLC's act and deed to the same extent as if the Agreement had been executed by Emerald WB LLC on the date of its original execution, effective as of the Effective Date.

[Signature Page Follows]

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THE PARTIES HERETO have executed this Agreement effective as of the day and year first above written.

GATHERER	PRODUCER
DAKOTA FLUID SOLUTIONS
LLC, FORMERLY KNOWN AS
MESA OIL SERVICES, LLC	EMERALD OIL, INC.
By: /s/ Tim Reynolds	By: /s/ McAndrew Rudisill
Name: Tim Reynolds	Name: McAndrew Rudisill
Title: Founding Partner	Title: Chief Executive Officer and President
Date: May 26, 2015	Date: May 26, 2015
	EMERALD WB LLC
	By:/s/ McAndrew Rudisill
	Name:  McAndrew Rudisill
	Title: President
	Date: May 26, 2015

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EX-10.7

Exhibit 10.7

EMPLOYMENT AGREEMENT

This EMPLOYMENT AGREEMENT (this “Agreement”) is made and entered into effective as of January 1, 2016 (the “Effective Date”) by and between Emerald Oil, Inc., a Delaware corporation (the “Company”), and McAndrew Rudisill (“Employee”).

WITNESSETH:

WHEREAS, the Company and Employee desire to enter into this Agreement pursuant to which Employee shall provide services to the Company as described herein.

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

Section 1. Position, Duties, and Responsibilities; Place of Performance.

(a)          During the Term of Employment (defined below), Employee shall be employed and serve as the Chief Executive Officer and President of the Company and shall have such duties and responsibilities that are commensurate with such title. The Employee shall report to the Board of the Company and shall carry out and perform all orders, directions and policies given to Employee by the Board of the Company consistent with his position and title.

(b)          Employee shall devote his best efforts, energy and time to the performance of his duties under this Agreement and shall not engage in any other business or occupation during the Term of Employment that materially interferes with Employee’s duties and responsibilities to serve and act in the Company’s best interests. Notwithstanding the foregoing, nothing herein shall preclude Employee from (i) serving as a member of the boards of directors or advisory boards (or their equivalents in the case of a non-corporate entity) of non-competing businesses, (ii) engaging in charitable activities and community affairs, and (iii) managing his personal investments and affairs; provided, however, that the activities set out in clauses (i), (ii), and (iii) shall be limited by Employee so as not to materially interfere, individually or in the aggregate, with the performance of his duties and responsibilities hereunder.

(c)          The Company agrees to employ Employee, and Employee agrees to serve the Company, on the terms and conditions set forth herein. The “Term of Employment” shall mean the period commencing on the Effective Date and, unless terminated sooner as provided in Section 4 hereof, continuing until December 31, 2016; provided, however, that the Term of Employment shall be extended automatically following December 31, 2016 for a one (1) year term and thereafter for successive one (1) year terms on the first anniversary of the then current term if neither the Company nor Employee has advised the other in writing in accordance with Section 10 at least sixty (60) days prior to the end of the then current term that such term will not be extended for an additional one (1) year term.

Section 2.          Compensation.

(a)          Base Salary. During the Term of Employment, Employee shall be paid an annualized base salary (the “Base Salary”), payable in United States dollars and less applicable taxes and deductions and in accordance with the regular payroll practices of the Company, of Four Hundred Fifty Thousand Dollars ($450,000) with increases, if any, as may be approved in writing by the Compensation Committee.

(b)          Annual Bonus. During the Company’s 2016 fiscal year starting January 1, 2016 and ending December 31, 2016 (and subsequent fiscal years, as applicable), subject to the satisfaction of applicable performance criteria and any other conditions as determined by the Compensation Committee, the Employee shall be eligible to receive an annual cash bonus award and annual equity bonus award (collectively, the “Annual Bonus”) as determined by the Compensation Committee in its sole and absolute discretion.

Section 3. Employee Benefits.

(a)        General. During the Term of Employment, Employee shall be entitled to participate in health insurance, retirement plans, directors’ and officers’ insurance coverage and other benefits provided to other senior executives of the Company, as in effect from time to time.

(b)       Vacation and Time Off. During each calendar year of the Term of Employment, Employee shall be eligible for twenty (20) days paid vacation, as well as sick pay and other paid and unpaid time off in accordance with the policies and practices of the Company, as in effect from time to time.

Section 4.          Termination.

(a)        General. The Term of Employment shall terminate earlier than as provided in Section 1(c) hereof upon the earliest to occur of (i) Employee’s death, (ii) a termination by reason of a disability, (iii) a termination by the Company, or (iv) a voluntary election by the Employee to terminate prior to the end of the Term of Employment (in each case, an “Early Termination”). In the event an Early Termination occurs as a result of (i) Employee’s death, (ii) a termination by reason of a disability, (iii) a termination by the Company without Cause (defined below), or (iv) a termination by Employee for Good Reason (defined below), then Employee or his estate or his beneficiaries, as the case may be, shall be entitled to the following:

(i) All accrued but unpaid Base Salary through the date of termination of Employee’s employment;

(ii) Any unpaid or unreimbursed expenses incurred in accordance with Section 5 below;

(iii) Any benefits provided under the Company’s employee benefit plans upon a termination of employment, in accordance with the terms contained therein;

(iv) The full amount of remaining and unpaid Base Salary that would have been paid to Employee had Employee served the duration of the Term of Employment;

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(v) A lump sum cash payment equal to eighteen (18) times the “applicable percentage” of the monthly COBRA premium cost applicable to Employee if Employee (or his dependents) were to elect COBRA coverage (“Monthly COBRA Premium”), or similar coverage as provided by similar state law, in connection with such termination, (for purposes hereof, the “applicable percentage” shall be the percentage of Employee’s health care premium costs covered by the Company as of the date of termination);

(vi) Any unpaid Annual Bonus in respect of any completed fiscal year that has ended prior to the date of such termination with such amount determined based on actual performance during such fiscal year as determined by the Compensation Committee;

(vii) Any Annual Bonus that would have been payable based on actual performance with respect to the year of termination in the absence of the Employee’s termination, death or disability, pro-rated for the period the Employee worked prior to his termination, death or disability, and payable at the same time as the bonus would have been paid in the absence of the Employee’s termination, death or disability; and

(viii) Immediate vesting of any and all equity or equity-related awards previously awarded to the Employee, irrespective of type of award.

(b) In the event Employee elects to voluntarily terminate his employment prior to the end of the Term of Employment without Good Reason, then Employee shall be entitled to the obligations set forth in Section 4(a)(i), (ii), (iii) and (vi).

(c) In the event Company terminates Employee for Cause, then Employee shall be entitled to the obligations set forth in Section 4(a)(i), (ii) and (iii), as well as a lump sum cash payment equal to twelve (12) times the Monthly COBRA Premium.

(d) If, upon a Change of Control of the Company or during the eighteen (18) month period following such Change of Control, Employee is terminated by the Company (or successor entity, as applicable) without Cause or Employee terminates Employee’s employment with Good Reason, then the Employee shall be entitled to the obligations set forth in Section 4(a)(i), (ii), (iii), (vi), one times the 2016 Base Salary, and a lump sum cash payment equal to twelve (12) times the Monthly COBRA Premium.

(e) The amounts payable to Employee under this Section 4 shall be paid within thirty (30) days from the date of such termination.

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(f) For purposes of this Agreement, “Cause” shall be defined as (i) a material breach of the terms and conditions of Employee’s employment agreement with the Company, (ii) Employee’s act(s) of gross negligence or willful misconduct in the course of Employee’s employment hereunder that is injurious to the Company or any affiliate of the Company, (iii) willful failure or refusal by Employee to perform in any material respect Employee’s duties or responsibilities, (iv) misappropriation by Employee of any assets of the Company or any or any affiliate of the Company, (v) embezzlement or fraud committed by Employee, or at Employee’s direction, (vi) Employee’s conviction of, or pleading “guilty” or “no contest” to a felony under state or federal law.

(g) For purposes of this Agreement, “Good Reason” shall mean, without Employee’s consent, (i) a material diminution in Employee’s title, duties, compensation or responsibilities, (ii) the failure of the Company to pay any compensation hereunder when due or to perform any other obligation of the Company under this Agreement, or (iii) the relocation of Employee’s principal place of employment by more than fifty (50) miles.

(h) For purposes of this Agreement, “Change of Control” shall mean the first to occur of any of the following: (i) “change of control event” with respect to the Company, within the meaning of Treas. Reg. 1.409A-3(i)(5); or (ii) During any period of two years, individuals who at the beginning of such period constitute the Board (and any new Director whose election by the Company’s shareholders was approved by a vote of at least a majority of the Directors then still in office who either were Directors at the beginning of the period or whose election or nomination for election was so approved) cease for any reason to constitute a majority thereof; or (iii) A merger, consolidation, or non-bankruptcy reorganization of the Company with or involving any other entity, other than a merger, consolidation, or non-bankruptcy reorganization that would result in the voting securities of the Company outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity) at least 50% of the combined voting power of the securities of the Company (or such surviving entity) outstanding immediately after such merger, consolidation, or non-bankruptcy reorganization.

Section 5. Reimbursement of Business Expenses. Employee is authorized to incur reasonable business expenses in carrying out his duties and responsibilities under this Agreement, and the Company shall promptly reimburse Employee for all such reasonable business expenses, subject to documentation in accordance with written Company policy, as in effect from time to time.

Section 6. Key-Man Insurance. At any time during the Term of Employment, the Company shall have the right to insure the life of Employee for the sole benefit of the Company, in such amounts, and with such terms, as it may determine. All premiums payable thereon shall be the obligation of the Company. Employee shall have no interest in any such policy, but agrees to cooperate with the Company in procuring such insurance by submitting to physical examinations, supplying all information required by the insurance company, and executing all necessary documents, provided that no financial obligation is imposed on Employee by any such documents. Upon the termination of his employment for any reason, Company will allow Employee to convert the insurance policy to a permanent personal life insurance policy.

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Section 7. Waiver and Amendments. Any waiver, alteration, amendment, or modification of any of the terms of this Agreement shall be valid only if made in writing and signed by each of the parties hereto. No waiver by either of the parties hereto of their rights hereunder shall be deemed to constitute a waiver with respect to any subsequent occurrences or transactions hereunder unless such waiver specifically states that it is to be construed as a continuing waiver.

Section 8. Severability. If any covenants or such other provisions of this Agreement are found to be invalid or unenforceable by a final determination of a court of competent jurisdiction, (a) the remaining terms and provisions hereof shall be unimpaired, and (b) the invalid or unenforceable term or provision hereof shall be deemed replaced by a term or provision that is valid and enforceable and that comes closest to expressing the intention of the invalid or unenforceable term or provision hereof.

Section 9. Governing Law. In the event of any dispute under this Agreement, or relating or arising under the employment relationship (a “Dispute”), this Agreement shall be governed by the laws of the State of Delaware. Each party shall bear his, her, or its own costs, including attorneys’ fees; provided, however, that nothing herein shall interfere with either party’s right to seek or receive damages or costs as may be allowed by applicable statutory law (such as, but not necessarily limited to, reasonable attorneys’ fees).

Section 10. Notices.

(a) Every notice or other communication relating to this Agreement shall be in writing, and shall be mailed to or delivered to the party for whom or which it is intended at such address as may from time to time be designated by it in a notice mailed or delivered to the other party as herein provided; provided, that unless and until some other address be so designated, all notices and communications by Employee to the Company shall be mailed or delivered to the Company at its principal executive office at 200 Columbine, Suite 500, Denver, Colorado 80206, and all notices and communications by the Company to Employee may be given to Employee personally or may be mailed to Employee at Employee’s last known address, as reflected in the Company’s records.

(b) Any notice so addressed shall be deemed to be given (i) if delivered by hand, on the date of such delivery, (ii) if mailed by courier or by overnight mail, on the first business day following the date of such mailing, and (iii) if mailed by registered or certified mail, on the third business day after the date of such mailing.

Section 11. Section Headings; Mutual Drafting.

(a) The headings of the sections and subsections of this Agreement are inserted for convenience only and shall not be deemed to constitute a part thereof or affect the meaning or interpretation of this Agreement or of any term or provision hereof.

(b) The parties are sophisticated and have been represented (or have had the opportunity to be represented) by their separate attorneys throughout the transactions contemplated by this Agreement in connection with the negotiation and drafting of this Agreement and any agreements and instruments executed in connection herewith. As a consequence, the parties do not intend that the presumptions of laws or rules relating to the interpretation of contracts against the drafter of any particular clause should be applied to this Agreement or any document or instrument executed in connection herewith, and therefore waive their effects.

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Section 12. Entire Agreement. This Agreement, together with any exhibits attached hereto, constitutes the entire understanding and agreement of the parties hereto regarding the employment of Employee during the Term of Employment. This Agreement supersedes all prior negotiations, discussions, correspondence, communications, understandings, and agreements between the parties relating to the employment of Employee during the Term of Employment.

Section 13. Dodd-Frank Act and Other Applicable Law Requirements. Employee agrees (i) to abide by any compensation recovery, recoupment, anti-hedging or other policy applicable to executives of the Company and its Affiliates, as may be in effect from time to time, as approved by the Board or a duly authorized committee thereof or as required by the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 (“Dodd-Frank Act”) or other applicable law, and (ii) that the terms and conditions of this Agreement shall be deemed automatically amended as may be necessary from time to time to ensure compliance by Employee and this Agreement with such policies, the Dodd-Frank Act, or other applicable law.

Section 14. Survival of Operative Sections. Upon any termination of Employee’s employment, the provisions of this Agreement (together with any related definitions set forth in Section 1 hereof) shall survive to the extent necessary to give effect to the provisions thereof.

Section 15. Counterparts. This Agreement may be executed in two or more counterparts, each of which shall be deemed to be an original but all of which together shall constitute one and the same instrument. The execution of this Agreement may be by actual or facsimile signature.

[Remainder of Page Intentionally Left Blank]

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IN WITNESS WHEREOF, the undersigned have executed this Agreement as of the date first above written.

COMPANY:
EMERALD OIL, INC.
By:	/s/ Seth Setrakian
Name:  Seth Setrakian
Title:    Chairman of the Compensation Committee
Date:    November 5, 2015
EMPLOYEE:
By:	/s/ McAndrew Rudisill
Name:  McAndrew Rudisill
Title:   Chief Executive Officer and President
Date:   November 5, 2015

7 

EX-10.8

Exhibit 10.8

EMPLOYMENT AGREEMENT

This EMPLOYMENT AGREEMENT (this “Agreement”) is made and entered into effective as of January 1, 2016 (the “Effective Date”) by and between Emerald Oil, Inc., a Delaware corporation (the “Company”), and Mike Dickinson (“Employee”).

WITNESSETH:

WHEREAS, the Company and Employee desire to enter into this Agreement pursuant to which Employee shall provide services to the Company as described herein.

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

Section 1. Position, Duties, and Responsibilities; Place of Performance.

(a)          During the Term of Employment (defined below), Employee shall be employed and serve as the Chief Operating Officer of the Company and shall have such duties and responsibilities that are commensurate with such title. The Employee shall report to the Board of the Company and shall carry out and perform all orders, directions and policies given to Employee by the Board of the Company consistent with his position and title.

(b)          Employee shall devote his best efforts, energy and time to the performance of his duties under this Agreement and shall not engage in any other business or occupation during the Term of Employment that materially interferes with Employee’s duties and responsibilities to serve and act in the Company’s best interests. Notwithstanding the foregoing, nothing herein shall preclude Employee from (i) serving as a member of the boards of directors or advisory boards (or their equivalents in the case of a non-corporate entity) of non-competing businesses, (ii) engaging in charitable activities and community affairs, and (iii) managing his personal investments and affairs; provided, however, that the activities set out in clauses (i), (ii), and (iii) shall be limited by Employee so as not to materially interfere, individually or in the aggregate, with the performance of his duties and responsibilities hereunder.

(c)          The Company agrees to employ Employee, and Employee agrees to serve the Company, on the terms and conditions set forth herein. The “Term of Employment” shall mean the period commencing on the Effective Date and, unless terminated sooner as provided in Section 4 hereof, continuing until December 31, 2016; provided, however, that the Term of Employment shall be extended automatically following December 31, 2016 for a one (1) year term and thereafter for successive one (1) year terms on the first anniversary of the then current term if neither the Company nor Employee has advised the other in writing in accordance with Section 10 at least sixty (60) days prior to the end of the then current term that such term will not be extended for an additional one (1) year term.

Section 2. Compensation.

(a)          Base Salary. During the Term of Employment, Employee shall be paid an annualized base salary (the “Base Salary”), payable in United States dollars and less applicable taxes and deductions and in accordance with the regular payroll practices of the Company, of Three Hundred Seventy-Five Thousand Dollars ($375,000) with increases, if any, as may be approved in writing by the Compensation Committee.

(b)          Annual Bonus. During the Company’s 2016 fiscal year starting January 1, 2016 and ending December 31, 2016 (and subsequent fiscal years, as applicable), subject to the satisfaction of applicable performance criteria and any other conditions as determined by the Compensation Committee, the Employee shall be eligible to receive an annual cash bonus award and annual equity bonus award (collectively, the “Annual Bonus”) as determined by the Compensation Committee in its sole and absolute discretion.

Section 3. Employee Benefits.

(a)   General. During the Term of Employment, Employee shall be entitled to participate in health insurance, retirement plans, directors’ and officers’ insurance coverage and other benefits provided to other senior executives of the Company, as in effect from time to time.

(b)   Vacation and Time Off. During each calendar year of the Term of Employment, Employee shall be eligible for twenty (20) days paid vacation, as well as sick pay and other paid and unpaid time off in accordance with the policies and practices of the Company, as in effect from time to time.

Section 4.          Termination.

(a)          General. The Term of Employment shall terminate earlier than as provided in Section 1(c) hereof upon the earliest to occur of (i) Employee’s death, (ii) a termination by reason of a disability, (iii) a termination by the Company, or (iv) a voluntary election by the Employee to terminate prior to the end of the Term of Employment (in each case, an “Early Termination”). In the event an Early Termination occurs as a result of (i) Employee’s death, (ii) a termination by reason of a disability, (iii) a termination by the Company without Cause (defined below), or (iv) a termination by Employee for Good Reason (defined below), then Employee or his estate or his beneficiaries, as the case may be, shall be entitled to the following:

(i) All accrued but unpaid Base Salary through the date of termination of Employee’s employment;

(ii) Any unpaid or unreimbursed expenses incurred in accordance with Section 5 below;

(iii) Any benefits provided under the Company’s employee benefit plans upon a termination of employment, in accordance with the terms contained therein;

(iv) The full amount of remaining and unpaid Base Salary that would have been paid to Employee had Employee served the duration of the Term of Employment;

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(v) A lump sum cash payment equal to eighteen (18) times the “applicable percentage” of the monthly COBRA premium cost applicable to Employee if Employee (or his dependents) were to elect COBRA coverage (“Monthly COBRA Premium”), or similar coverage as provided by similar state law, in connection with such termination, (for purposes hereof, the “applicable percentage” shall be the percentage of Employee’s health care premium costs covered by the Company as of the date of termination);

(vi) Any unpaid Annual Bonus in respect of any completed fiscal year that has ended prior to the date of such termination with such amount determined based on actual performance during such fiscal year as determined by the Compensation Committee;

(vii)   Any Annual Bonus that would have been payable based on actual performance with respect to the year of termination in the absence of the Employee’s termination, death or disability, pro-rated for the period the Employee worked prior to his termination, death or disability, and payable at the same time as the bonus would have been paid in the absence of the Employee’s termination, death or disability; and

(viii)   Immediate vesting of any and all equity or equity-related awards previously awarded to the Employee, irrespective of type of award.

(b) In the event Employee elects to voluntarily terminate his employment prior to the end of the Term of Employment without Good Reason, then Employee shall be entitled to the obligations set forth in Section 4(a)(i), (ii), (iii) and (vi).

(c) In the event Company terminates Employee for Cause, then Employee shall be entitled to the obligations set forth in Section 4(a)(i), (ii) and (iii), as well as a lump sum cash payment equal to twelve (12) times the Monthly COBRA Premium.

(d) If, upon a Change of Control of the Company or during the eighteen (18) month period following such Change of Control, Employee is terminated by the Company (or successor entity, as applicable) without Cause or Employee terminates Employee’s employment with Good Reason, then the Employee shall be entitled to the obligations set forth in Section 4(a)(i), (ii), (iii), (vi), one times the 2016 Base Salary, and a lump sum cash payment equal to twelve (12) times the Monthly COBRA Premium.

(e) The amounts payable to Employee under this Section 4 shall be paid within thirty (30) days from the date of such termination.

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(f) For purposes of this Agreement, “Cause” shall be defined as (i) a material breach of the terms and conditions of Employee’s employment agreement with the Company, (ii) Employee’s act(s) of gross negligence or willful misconduct in the course of Employee’s employment hereunder that is injurious to the Company or any affiliate of the Company, (iii) willful failure or refusal by Employee to perform in any material respect Employee’s duties or responsibilities, (iv) misappropriation by Employee of any assets of the Company or any or any affiliate of the Company, (v) embezzlement or fraud committed by Employee, or at Employee’s direction, (vi) Employee’s conviction of, or pleading “guilty” or “no contest” to a felony under state or federal law.

(g) For purposes of this Agreement, “Good Reason” shall mean, without Employee’s consent, (i) a material diminution in Employee’s title, duties, compensation or responsibilities, (ii) the failure of the Company to pay any compensation hereunder when due or to perform any other obligation of the Company under this Agreement, or (iii) the relocation of Employee’s principal place of employment by more than fifty (50) miles.

(h) For purposes of this Agreement, “Change of Control” shall mean the first to occur of any of the following: (i) “change of control event” with respect to the Company, within the meaning of Treas. Reg. 1.409A-3(i)(5); or (ii) During any period of two years, individuals who at the beginning of such period constitute the Board (and any new Director whose election by the Company’s shareholders was approved by a vote of at least a majority of the Directors then still in office who either were Directors at the beginning of the period or whose election or nomination for election was so approved) cease for any reason to constitute a majority thereof; or (iii) A merger, consolidation, or non-bankruptcy reorganization of the Company with or involving any other entity, other than a merger, consolidation, or non-bankruptcy reorganization that would result in the voting securities of the Company outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity) at least 50% of the combined voting power of the securities of the Company (or such surviving entity) outstanding immediately after such merger, consolidation, or non-bankruptcy reorganization.

Section 5. Reimbursement of Business Expenses. Employee is authorized to incur reasonable business expenses in carrying out his duties and responsibilities under this Agreement, and the Company shall promptly reimburse Employee for all such reasonable business expenses, subject to documentation in accordance with written Company policy, as in effect from time to time.

Section 6. Key-Man Insurance. At any time during the Term of Employment, the Company shall have the right to insure the life of Employee for the sole benefit of the Company, in such amounts, and with such terms, as it may determine. All premiums payable thereon shall be the obligation of the Company. Employee shall have no interest in any such policy, but agrees to cooperate with the Company in procuring such insurance by submitting to physical examinations, supplying all information required by the insurance company, and executing all necessary documents, provided that no financial obligation is imposed on Employee by any such documents. Upon the termination of his employment for any reason, Company will allow Employee to convert the insurance policy to a permanent personal life insurance policy.

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Section 7. Waiver and Amendments. Any waiver, alteration, amendment, or modification of any of the terms of this Agreement shall be valid only if made in writing and signed by each of the parties hereto. No waiver by either of the parties hereto of their rights hereunder shall be deemed to constitute a waiver with respect to any subsequent occurrences or transactions hereunder unless such waiver specifically states that it is to be construed as a continuing waiver.

Section 8. Severability. If any covenants or such other provisions of this Agreement are found to be invalid or unenforceable by a final determination of a court of competent jurisdiction, (a) the remaining terms and provisions hereof shall be unimpaired, and (b) the invalid or unenforceable term or provision hereof shall be deemed replaced by a term or provision that is valid and enforceable and that comes closest to expressing the intention of the invalid or unenforceable term or provision hereof.

Section 9. Governing Law. In the event of any dispute under this Agreement, or relating or arising under the employment relationship (a “Dispute”), this Agreement shall be governed by the laws of the State of Delaware. Each party shall bear his, her, or its own costs, including attorneys’ fees; provided, however, that nothing herein shall interfere with either party’s right to seek or receive damages or costs as may be allowed by applicable statutory law (such as, but not necessarily limited to, reasonable attorneys’ fees).

Section 10. Notices.

(a)   Every notice or other communication relating to this Agreement shall be in writing, and shall be mailed to or delivered to the party for whom or which it is intended at such address as may from time to time be designated by it in a notice mailed or delivered to the other party as herein provided; provided, that unless and until some other address be so designated, all notices and communications by Employee to the Company shall be mailed or delivered to the Company at its principal executive office at 200 Columbine, Suite 500, Denver, Colorado 80206, and all notices and communications by the Company to Employee may be given to Employee personally or may be mailed to Employee at Employee’s last known address, as reflected in the Company’s records.

(b)   Any notice so addressed shall be deemed to be given (i) if delivered by hand, on the date of such delivery, (ii) if mailed by courier or by overnight mail, on the first business day following the date of such mailing, and (iii) if mailed by registered or certified mail, on the third business day after the date of such mailing.

Section 11. Section Headings; Mutual Drafting.

(a)   The headings of the sections and subsections of this Agreement are inserted for convenience only and shall not be deemed to constitute a part thereof or affect the meaning or interpretation of this Agreement or of any term or provision hereof.

(b)   The parties are sophisticated and have been represented (or have had the opportunity to be represented) by their separate attorneys throughout the transactions contemplated by this Agreement in connection with the negotiation and drafting of this Agreement and any agreements and instruments executed in connection herewith. As a consequence, the parties do not intend that the presumptions of laws or rules relating to the interpretation of contracts against the drafter of any particular clause should be applied to this Agreement or any document or instrument executed in connection herewith, and therefore waive their effects.

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Section 12. Entire Agreement. This Agreement, together with any exhibits attached hereto, constitutes the entire understanding and agreement of the parties hereto regarding the employment of Employee during the Term of Employment. This Agreement supersedes all prior negotiations, discussions, correspondence, communications, understandings, and agreements between the parties relating to the employment of Employee during the Term of Employment.

Section 13. Dodd-Frank Act and Other Applicable Law Requirements. Employee agrees (i) to abide by any compensation recovery, recoupment, anti-hedging or other policy applicable to executives of the Company and its Affiliates, as may be in effect from time to time, as approved by the Board or a duly authorized committee thereof or as required by the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 (“Dodd-Frank Act”) or other applicable law, and (ii) that the terms and conditions of this Agreement shall be deemed automatically amended as may be necessary from time to time to ensure compliance by Employee and this Agreement with such policies, the Dodd-Frank Act, or other applicable law.

Section 14. Survival of Operative Sections. Upon any termination of Employee’s employment, the provisions of this Agreement (together with any related definitions set forth in Section 1 hereof) shall survive to the extent necessary to give effect to the provisions thereof.

Section 15. Counterparts. This Agreement may be executed in two or more counterparts, each of which shall be deemed to be an original but all of which together shall constitute one and the same instrument. The execution of this Agreement may be by actual or facsimile signature.

[Remainder of Page Intentionally Left Blank]

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IN WITNESS WHEREOF, the undersigned have executed this Agreement as of the date first above written.

COMPANY:
EMERALD OIL, INC.
By:	/s/ Seth Setrakian
Name:  Seth Setrakian
Title:    Chairman of the Compensation Committee
Date:    November 5, 2015
EMPLOYEE:
By:	/s/ Mike Dickinson
Name:  Mike Dickinson
Title:    Chief Operating Officer
Date:    November 5, 2015

7

EX-10.9

Exhibit 10.9

EMPLOYMENT AGREEMENT

This EMPLOYMENT AGREEMENT (this “Agreement”) is made and entered into effective as of January 1, 2016 (the “Effective Date”) by and between Emerald Oil, Inc., a Delaware corporation (the “Company”), and Ryan Smith (“Employee”).

WITNESSETH:

WHEREAS, the Company and Employee desire to enter into this Agreement pursuant to which Employee shall provide services to the Company as described herein.

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

Section 1. Position, Duties, and Responsibilities; Place of Performance.

(a)          During the Term of Employment (defined below), Employee shall be employed and serve as the Chief Financial Officer of the Company and shall have such duties and responsibilities that are commensurate with such title. The Employee shall report to the Board of the Company and shall carry out and perform all orders, directions and policies given to Employee by the Board of the Company consistent with his position and title.

(b)          Employee shall devote his best efforts, energy and time to the performance of his duties under this Agreement and shall not engage in any other business or occupation during the Term of Employment that materially interferes with Employee’s duties and responsibilities to serve and act in the Company’s best interests. Notwithstanding the foregoing, nothing herein shall preclude Employee from (i) serving as a member of the boards of directors or advisory boards (or their equivalents in the case of a non-corporate entity) of non-competing businesses, (ii) engaging in charitable activities and community affairs, and (iii) managing his personal investments and affairs; provided, however, that the activities set out in clauses (i), (ii), and (iii) shall be limited by Employee so as not to materially interfere, individually or in the aggregate, with the performance of his duties and responsibilities hereunder.

(c)          The Company agrees to employ Employee, and Employee agrees to serve the Company, on the terms and conditions set forth herein. The “Term of Employment” shall mean the period commencing on the Effective Date and, unless terminated sooner as provided in Section 4 hereof, continuing until December 31, 2016; provided, however, that the Term of Employment shall be extended automatically following December 31, 2016 for a one (1) year term and thereafter for successive one (1) year terms on the first anniversary of the then current term if neither the Company nor Employee has advised the other in writing in accordance with Section 10 at least sixty (60) days prior to the end of the then current term that such term will not be extended for an additional one (1) year term.

Section 2. Compensation.

(a)          Base Salary. During the Term of Employment, Employee shall be paid an annualized base salary (the “Base Salary”), payable in United States dollars and less applicable taxes and deductions and in accordance with the regular payroll practices of the Company, of Three Hundred Twenty-Five Thousand Dollars ($325,000) with increases, if any, as may be approved in writing by the Compensation Committee.

(b)          Annual Bonus. During the Company’s 2016 fiscal year starting January 1, 2016 and ending December 31, 2016 (and subsequent fiscal years, as applicable), subject to the satisfaction of applicable performance criteria and any other conditions as determined by the Compensation Committee, the Employee shall be eligible to receive an annual cash bonus award and annual equity bonus award (collectively, the “Annual Bonus”) as determined by the Compensation Committee in its sole and absolute discretion.

Section 3. Employee Benefits.

(a)         General. During the Term of Employment, Employee shall be entitled to participate in health insurance, retirement plans, directors’ and officers’ insurance coverage and other benefits provided to other senior executives of the Company, as in effect from time to time.

(b)        Vacation and Time Off. During each calendar year of the Term of Employment, Employee shall be eligible for twenty (20) days paid vacation, as well as sick pay and other paid and unpaid time off in accordance with the policies and practices of the Company, as in effect from time to time.

Section 4.          Termination.

(a)          General. The Term of Employment shall terminate earlier than as provided in Section 1(c) hereof upon the earliest to occur of (i) Employee’s death, (ii) a termination by reason of a disability, (iii) a termination by the Company, or (iv) a voluntary election by the Employee to terminate prior to the end of the Term of Employment (in each case, an “Early Termination”). In the event an Early Termination occurs as a result of (i) Employee’s death, (ii) a termination by reason of a disability, (iii) a termination by the Company without Cause (defined below), or (iv) a termination by Employee for Good Reason (defined below), then Employee or his estate or his beneficiaries, as the case may be, shall be entitled to the following:

(i) All accrued but unpaid Base Salary through the date of termination of Employee’s employment;

(ii) Any unpaid or unreimbursed expenses incurred in accordance with Section 5 below;

(iii) Any benefits provided under the Company’s employee benefit plans upon a termination of employment, in accordance with the terms contained therein;

(iv) The full amount of remaining and unpaid Base Salary that would have been paid to Employee had Employee served the duration of the Term of Employment;

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(v) A lump sum cash payment equal to eighteen (18) times the “applicable percentage” of the monthly COBRA premium cost applicable to Employee if Employee (or his dependents) were to elect COBRA coverage (“Monthly COBRA Premium”), or similar coverage as provided by similar state law, in connection with such termination, (for purposes hereof, the “applicable percentage” shall be the percentage of Employee’s health care premium costs covered by the Company as of the date of termination);

(vi) Any unpaid Annual Bonus in respect of any completed fiscal year that has ended prior to the date of such termination with such amount determined based on actual performance during such fiscal year as determined by the Compensation Committee;

(vii) Any Annual Bonus that would have been payable based on actual performance with respect to the year of termination in the absence of the Employee’s termination, death or disability, pro-rated for the period the Employee worked prior to his termination, death or disability, and payable at the same time as the bonus would have been paid in the absence of the Employee’s termination, death or disability; and

(viii) Immediate vesting of any and all equity or equity-related awards previously awarded to the Employee, irrespective of type of award.

(b) In the event Employee elects to voluntarily terminate his employment prior to the end of the Term of Employment without Good Reason, then Employee shall be entitled to the obligations set forth in Section 4(a)(i), (ii), (iii) and (vi).

(c) In the event Company terminates Employee for Cause, then Employee shall be entitled to the obligations set forth in Section 4(a)(i), (ii) and (iii), as well as a lump sum cash payment equal to twelve (12) times the Monthly COBRA Premium.

(d) If, upon a Change of Control of the Company or during the eighteen (18) month period following such Change of Control, Employee is terminated by the Company (or successor entity, as applicable) without Cause or Employee terminates Employee’s employment with Good Reason, then the Employee shall be entitled to the obligations set forth in Section 4(a)(i), (ii), (iii), (vi), one times the 2016 Base Salary, and a lump sum cash payment equal to twelve (12) times the Monthly COBRA Premium.

(e) The amounts payable to Employee under this Section 4 shall be paid within thirty (30) days from the date of such termination.

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(f) For purposes of this Agreement, “Cause” shall be defined as (i) a material breach of the terms and conditions of Employee’s employment agreement with the Company, (ii) Employee’s act(s) of gross negligence or willful misconduct in the course of Employee’s employment hereunder that is injurious to the Company or any affiliate of the Company, (iii) willful failure or refusal by Employee to perform in any material respect Employee’s duties or responsibilities, (iv) misappropriation by Employee of any assets of the Company or any or any affiliate of the Company, (v) embezzlement or fraud committed by Employee, or at Employee’s direction, (vi) Employee’s conviction of, or pleading “guilty” or “no contest” to a felony under state or federal law.

(g) For purposes of this Agreement, “Good Reason” shall mean, without Employee’s consent, (i) a material diminution in Employee’s title, duties, compensation or responsibilities, (ii) the failure of the Company to pay any compensation hereunder when due or to perform any other obligation of the Company under this Agreement, or (iii) the relocation of Employee’s principal place of employment by more than fifty (50) miles.

(h) For purposes of this Agreement, “Change of Control” shall mean the first to occur of any of the following: (i) “change of control event” with respect to the Company, within the meaning of Treas. Reg. 1.409A-3(i)(5); or (ii) During any period of two years, individuals who at the beginning of such period constitute the Board (and any new Director whose election by the Company’s shareholders was approved by a vote of at least a majority of the Directors then still in office who either were Directors at the beginning of the period or whose election or nomination for election was so approved) cease for any reason to constitute a majority thereof; or (iii) A merger, consolidation, or non-bankruptcy reorganization of the Company with or involving any other entity, other than a merger, consolidation, or non-bankruptcy reorganization that would result in the voting securities of the Company outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity) at least 50% of the combined voting power of the securities of the Company (or such surviving entity) outstanding immediately after such merger, consolidation, or non-bankruptcy reorganization.

Section 5. Reimbursement of Business Expenses. Employee is authorized to incur reasonable business expenses in carrying out his duties and responsibilities under this Agreement, and the Company shall promptly reimburse Employee for all such reasonable business expenses, subject to documentation in accordance with written Company policy, as in effect from time to time.

Section 6. Key-Man Insurance. At any time during the Term of Employment, the Company shall have the right to insure the life of Employee for the sole benefit of the Company, in such amounts, and with such terms, as it may determine. All premiums payable thereon shall be the obligation of the Company. Employee shall have no interest in any such policy, but agrees to cooperate with the Company in procuring such insurance by submitting to physical examinations, supplying all information required by the insurance company, and executing all necessary documents, provided that no financial obligation is imposed on Employee by any such documents. Upon the termination of his employment for any reason, Company will allow Employee to convert the insurance policy to a permanent personal life insurance policy.

4

Section 7. Waiver and Amendments. Any waiver, alteration, amendment, or modification of any of the terms of this Agreement shall be valid only if made in writing and signed by each of the parties hereto. No waiver by either of the parties hereto of their rights hereunder shall be deemed to constitute a waiver with respect to any subsequent occurrences or transactions hereunder unless such waiver specifically states that it is to be construed as a continuing waiver.

Section 8. Severability. If any covenants or such other provisions of this Agreement are found to be invalid or unenforceable by a final determination of a court of competent jurisdiction, (a) the remaining terms and provisions hereof shall be unimpaired, and (b) the invalid or unenforceable term or provision hereof shall be deemed replaced by a term or provision that is valid and enforceable and that comes closest to expressing the intention of the invalid or unenforceable term or provision hereof.

Section 9. Governing Law. In the event of any dispute under this Agreement, or relating or arising under the employment relationship (a “Dispute”), this Agreement shall be governed by the laws of the State of Delaware. Each party shall bear his, her, or its own costs, including attorneys’ fees; provided, however, that nothing herein shall interfere with either party’s right to seek or receive damages or costs as may be allowed by applicable statutory law (such as, but not necessarily limited to, reasonable attorneys’ fees).

Section 10. Notices.

(a) Every notice or other communication relating to this Agreement shall be in writing, and shall be mailed to or delivered to the party for whom or which it is intended at such address as may from time to time be designated by it in a notice mailed or delivered to the other party as herein provided; provided, that unless and until some other address be so designated, all notices and communications by Employee to the Company shall be mailed or delivered to the Company at its principal executive office at 200 Columbine, Suite 500, Denver, Colorado 80206, and all notices and communications by the Company to Employee may be given to Employee personally or may be mailed to Employee at Employee’s last known address, as reflected in the Company’s records.

(b) Any notice so addressed shall be deemed to be given (i) if delivered by hand, on the date of such delivery, (ii) if mailed by courier or by overnight mail, on the first business day following the date of such mailing, and (iii) if mailed by registered or certified mail, on the third business day after the date of such mailing.

Section 11. Section Headings; Mutual Drafting.

(a) The headings of the sections and subsections of this Agreement are inserted for convenience only and shall not be deemed to constitute a part thereof or affect the meaning or interpretation of this Agreement or of any term or provision hereof.

(b) The parties are sophisticated and have been represented (or have had the opportunity to be represented) by their separate attorneys throughout the transactions contemplated by this Agreement in connection with the negotiation and drafting of this Agreement and any agreements and instruments executed in connection herewith. As a consequence, the parties do not intend that the presumptions of laws or rules relating to the interpretation of contracts against the drafter of any particular clause should be applied to this Agreement or any document or instrument executed in connection herewith, and therefore waive their effects.

5

Section 12. Entire Agreement. This Agreement, together with any exhibits attached hereto, constitutes the entire understanding and agreement of the parties hereto regarding the employment of Employee during the Term of Employment. This Agreement supersedes all prior negotiations, discussions, correspondence, communications, understandings, and agreements between the parties relating to the employment of Employee during the Term of Employment.

Section 13. Dodd-Frank Act and Other Applicable Law Requirements. Employee agrees (i) to abide by any compensation recovery, recoupment, anti-hedging or other policy applicable to executives of the Company and its Affiliates, as may be in effect from time to time, as approved by the Board or a duly authorized committee thereof or as required by the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 (“Dodd-Frank Act”) or other applicable law, and (ii) that the terms and conditions of this Agreement shall be deemed automatically amended as may be necessary from time to time to ensure compliance by Employee and this Agreement with such policies, the Dodd-Frank Act, or other applicable law.

Section 14. Survival of Operative Sections. Upon any termination of Employee’s employment, the provisions of this Agreement (together with any related definitions set forth in Section 1 hereof) shall survive to the extent necessary to give effect to the provisions thereof.

Section 15. Counterparts. This Agreement may be executed in two or more counterparts, each of which shall be deemed to be an original but all of which together shall constitute one and the same instrument. The execution of this Agreement may be by actual or facsimile signature.

[Remainder of Page Intentionally Left Blank]

6

IN WITNESS WHEREOF, the undersigned have executed this Agreement as of the date first above written.

COMPANY:
EMERALD OIL, INC.
By:	/s/ Seth Setrakian
Name:  Seth Setrakian
Title:    Chairman of the Compensation Committee
Date:    November 5, 2015
EMPLOYEE:
By:	/s/ Ryan Smith
Name:  Ryan Smith
Title:    Chief Financial Officer
Date:    November 5, 2015

7

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.

November 6, 2015	/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, Ryan Smith, 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.

November 6, 2015	/s/ RYAN SMITH
	Ryan Smith
	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 September 30, 2015, 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.

November 6, 2015	/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 September 30, 2015, referred to as the report, I, Ryan Smith, 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.

November 6, 2015	/s/ RYAN SMITH
	Ryan Smith
	Chief Financial Officer
	(principal financial officer)

XML

STOCK OPTIONS AND WARRANTS (Schedule of Stock Options Outstanding) (Details) - $ / shares	9 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of options outstanding (in Shares)	40,536	59,746
Stock options outstanding, weighted average remaining contract life (years) (in Duration)	2 years 8 months 19 days
Stock options outstanding weighted average exercise price (in Dollars per Share)	$ 148.78	$ 171.20
Number of options exercisable (in Shares)	30,759
Stock options exercisable, weighted average remaining contract life (years) (in Duration)	2 years 4 months 28 days
Stock options exercisable, weighted average exercise price (in Dollars per Share)	$ 150.83
Year of Grant 2015 [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of options outstanding (in Shares)
Stock options outstanding, weighted average remaining contract life (years) (in Duration)
Stock options outstanding weighted average exercise price (in Dollars per Share)
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 2014 [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of options outstanding (in Shares)	15,781
Stock options outstanding, weighted average remaining contract life (years) (in Duration)	3 years 2 months 5 days
Stock options outstanding weighted average exercise price (in Dollars per Share)	$ 143.48
Number of options exercisable (in Shares)	8,804
Stock options exercisable, weighted average remaining contract life (years) (in Duration)	2 years 11 months 23 days
Stock options exercisable, weighted average exercise price (in Dollars per Share)	$ 145.17
Year of Grant 2013 [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of options outstanding (in Shares)	8,755
Stock options outstanding, weighted average remaining contract life (years) (in Duration)	3 years 4 months 10 days
Stock options outstanding weighted average exercise price (in Dollars per Share)	$ 140.95
Number of options exercisable (in Shares)	5,955
Stock options exercisable, weighted average remaining contract life (years) (in Duration)	2 years 11 months 1 day
Stock options exercisable, weighted average exercise price (in Dollars per Share)	$ 139.27
Year of Grant 2012 [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of options outstanding (in Shares)	14,731
Stock options outstanding, weighted average remaining contract life (years) (in Duration)	1 year 9 months 26 days
Stock options outstanding weighted average exercise price (in Dollars per Share)	$ 156.80
Number of options exercisable (in Shares)	14,731
Stock options exercisable, weighted average remaining contract life (years) (in Duration)	1 year 9 months 26 days
Stock options exercisable, weighted average exercise price (in Dollars per Share)	$ 156.80
Year of Grant Prior to 2012 [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of options outstanding (in Shares)	1,269
Stock options outstanding, weighted average remaining contract life (years) (in Duration)	2 years 11 months 19 days
Stock options outstanding weighted average exercise price (in Dollars per Share)	$ 174.96
Number of options exercisable (in Shares)	1,269
Stock options exercisable, weighted average remaining contract life (years) (in Duration)	2 years 11 months 19 days
Stock options exercisable, weighted average exercise price (in Dollars per Share)	$ 174.96

XML

FAIR VALUE (Schedule of Fair Value of Warrants Liability Measured on Recurring Basis, Unobservable Inputs) (Details) - USD ($)	9 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Rollforward of Level 3 warrants liability measured at fair value using level 3 on a recurring basis
Warrants liability, balance at beginning of period	$ (2,199,000)	$ (15,703,000)
Change in Fair Value of Warrant Liability	2,012,000	13,504,000
Warrants liability, balance at end of period	$ (187,000)	$ (2,199,000)

XML

FAIR VALUE (Narrative) (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Feb. 19, 2013
Fair Value [Abstract]
Fair value of warrant liability at issuance					$ 8,626,000
Warrant revaluation gain (expense)	$ 221,000	$ 216,000	$ 2,012,000	$ (1,751,000)
Fair value of convertible notes	$ 39,400,000		$ 39,400,000

XML

RELATED PARTY TRANSACTIONS (Narrative) (Details) - USD ($)		1 Months Ended					2 Months Ended	9 Months Ended
	May. 16, 2014	Sep. 30, 2015	Feb. 28, 2015	Oct. 31, 2013	Jun. 30, 2013	Feb. 28, 2013	May. 31, 2015	Sep. 30, 2015	Sep. 30, 2014
Related Party Transaction [Line Items]
Equity offering (in Shares)			1,357,955
Issue price per share (in Dollars per Share)			$ 22.40
Proceeds from issuance of common stock		$ 2,300,000	$ 29,400,000				$ 16,400,000	$ 48,049,115
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)						255,732
Related party transaction, common stock purchasable with warrants issued (in Shares)						255,732
Related party transaction, initial exercise price of common stock purchasable with warrants issued (in Dollars per Share)						$ 115.40
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)						255,732
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)				254,643	139,280
Related party transaction and company, shares registered for resale with the SEC under registration statement Form S-3 (in Shares)	393,923
Related party transaction and company, shares underlying warrants registered for resale with the SEC under registration statement Form S-3 (in Shares)	255,732
Equity offering (in Shares)			669,643

XML

ASSET RETIREMENT OBLIGATION (Tables)

9 Months Ended

Sep. 30, 2015

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 nine months ended September 30, 2015 and the year ended December 31, 2014:

	Nine Months Ended September 30, 2015		Year Ended December 31, 2014
Beginning Asset Retirement Obligation	$	2,671,975	$	692,137
Revision of Previous Estimates		—		148,968
Liabilities Incurred or Acquired		440,536		1,817,939
Accretion of Discount on Asset Retirement Obligations		153,007		104,803
Wells Settled Through P&A		—		(72,555	)
Liabilities Associated with Properties Sold		—		(19,317	)
Ending Asset Retirement Obligation	$	3,265,518	$	2,671,975

XML

DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT (Schedule of Open Commodity Swap Contracts) (Details) - Crude Oil [Member] - Put [Member]	Sep. 30, 2015 USD ($) $ / shares
Settlement Period October 2015 - December 2015
Derivative [Line Items]
Daily Volume Oil (in Barrels)	4,000
Put Option Fixed Price Per Bbl (in Dollars per Unit)	55.00
Total Volume (in Barrels)	368,000
Premium Paid per Bbl (in Dollars per Unit)	4.88
Total Premiums Due | $	$ 1,795,840
Settlement Period January 2016 - December 2016
Derivative [Line Items]
Daily Volume Oil (in Barrels)	3,000
Put Option Fixed Price Per Bbl (in Dollars per Unit)	60.00
Total Volume (in Barrels)	1,098,000
Premium Paid per Bbl (in Dollars per Unit)	7.54
Total Premiums Due | $	$ 8,278,920

XML

CONVERTIBLE NOTES (Narrative) (Details)		1 Months Ended	12 Months Ended
	Mar. 24, 2014 USD ($)	Dec. 31, 2014 USD ($) shares	Dec. 31, 2014 USD ($)	Sep. 30, 2015 USD ($) $ / shares shares
Debt Instrument [Line Items]
Convertible senior notes amount outstanding				$ 151,500,000
Amount of convertible debt extinguished through equity issuance		$ 21,000,000
Convertible Debt [Member]
Debt Instrument [Line Items]
Notes issuance date (Date)	Mar. 24, 2014
Notes, amount issued	$ 172,500,000
Notes interest rate (in Percent)	2.00%
Notes maturity date (in Date)	Apr. 01, 2019
Convertible senior notes amount outstanding				$ 151,500,000
Shares issuable on conversion of convertible notes (in Shares) | shares				863,248
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) | $ / shares				5.698
Convertible notes, conversion rate, principal amount per 5.698 shares				$ 1,000
Convertible notes, conversion rate, price per share (in Dollars per Share) | $ / shares				$ 175.60
Convertible notes, fundamental change purchase price percentage (in Percent)				100.00%
Convertible notes, event of default, minimum percent of outstanding principal required among noteholders to trigger prepayment demand under event of default (in Percent)				25.00%
Shares issued in debt conversion (in Shares) | shares		536,091
Amount of convertible debt extinguished through equity issuance		$ 21,000,000
Number of common shares underlying convertible debt under original indenture agreement (in Shares) | shares		119,658
Debt conversion expense recognized			$ 10,438,080

XML

STOCK OPTIONS AND WARRANTS (Narrative) (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock options granted (in Shares)
Stock Option [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock options granted (in Shares)			0
Share based compensation, net of tax	$ (15,200)	$ 337,809	$ 142,276	$ 810,419
Share based compensation, tax	0	0	0	0
Share-based compensation capitalized	(5,035)	$ 187,017	106,995	$ 595,628
Unrecognized compensation relating to options granted	$ 183,140		$ 183,140
Period for recognition of unrecognized compensation costs related to nonvested share based compensation (Duration)				10 months 29 days
Warrant [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Warrants expired or forfeited (in Shares)			0

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COMMITMENTS AND CONTINGENCIES (Narrative) (Details)	Sep. 30, 2015 USD ($) $ / Unit $ / bbl MMBbls Bcf
Executive Compensation [Abstract]
Percent of 2014 earned cash bonus of CEO and Vice Chair of BOD to be paid in equity by early 2016 (in Percent)	50.00%
Percent of 2014 annual equity bonus of CEO and Vice Chair of BOD to be paid in equity by early 2016 (in Percent)	50.00%
Oil, Natural Gas and Produced Water Transportation and Processing Commitments [Abstract]
Gross barrels of oil committed to be delivered (in Millions of barrels)	16.4
Oil delivery commitment, price per barrel (in USD/bbl) | $ / bbl	1.21
Gross natural gas committed to be delivered (in Billions of Cubic Feet) | Bcf	10.9
Natural gas delivery commitment, price per million cubic feet (in USD/Mcf) | $ / Unit	1.67
Gross barrels of produced water committed to be delivered (in Millions of barrels)	28.2
Produced water delivery commitment, price per barrel (in USD/bbl) | $ / bbl	.82
Accrued volume commitment deficiency fee expense | $	$ 1,000,000

XML

FAIR VALUE (Schedule of Fair Value of Financial Instruments Measured on Recurring Basis) (Details) - USD ($)	Sep. 30, 2015	Dec. 31, 2014
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Warrant Liability - Long Term Liability	$ (187,000)	$ (2,199,000)
Commodity Derivatives - Current Asset (oil puts at 2015-09-30 and oil swaps at 2014-12-31)	$ 6,336,057	$ 5,044,125
Commodity Derivatives - Long Term Liabilitiy (oil put premiums)
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 Asset (oil puts at 2015-09-30 and oil swaps at 2014-12-31)
Commodity Derivatives - Current Liabilitiy (oil put premiums)
Commodity Derivatives - Long Term Liabilitiy (oil put premiums)
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 Asset (oil puts at 2015-09-30 and oil swaps at 2014-12-31)	$ 14,310,070	$ 5,044,125
Commodity Derivatives - Current Liabilitiy (oil put premiums)	(7,974,014)
Commodity Derivatives - Long Term Liabilitiy (oil put premiums)	(2,067,594)
Total	7,711,127	5,044,125
Significant Unobservable Inputs (Level 3) [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Warrant Liability - Long Term Liability	$ (187,000)	$ (2,199,000)
Commodity Derivatives - Current Asset (oil puts at 2015-09-30 and oil swaps at 2014-12-31)
Commodity Derivatives - Current Liabilitiy (oil put premiums)
Commodity Derivatives - Long Term Liabilitiy (oil put premiums)
Total	$ (187,000)	$ (2,199,000)

XML

OIL AND NATURAL GAS PROPERTIES

9 Months Ended

Sep. 30, 2015

Oil and Natural Gas Properties [Abstract]

OIL AND NATURAL GAS PROPERTIES

NOTE 4  OIL AND NATURAL GAS PROPERTIES

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

Joint Venture Agreement

On July 31, 2015, the Company entered into a purchase and sale agreement with Koch Exploration Company, LLC (“Koch Exploration”), a wholly owned subsidiary of Koch Industries Inc. Subject to customary closing conditions, Koch Exploration acquired a 30% working interest in approximately 25,000 undeveloped net acres held by the Company in McKenzie County, North Dakota and approximately 4,400 undeveloped net acres held by the Company in Richland County, Montana for approximately $17.4 million. Koch Exploration reimbursed the Company approximately $5.4 million for its proportionate share of recently drilled and uncompleted wells in southern McKenzie County, North Dakota. Total proceeds to the Company upon closing the transaction were approximately $22.8 million and all proceeds were used to pay down outstanding borrowings under the Company’s Credit Facility (see Note 15 Subsequent Events – Joint Venture Agreement).

Acquisitions

On September 2, 2014, the Company acquired approximately 30,500 net acres located in McKenzie, Billings and Dunn Counties of North Dakota from an unrelated third party for approximately $71.2 million in cash and the assignment of approximately 4,300 net acres held by the Company in Williams County, North Dakota.

The following table summarizes the purchase price and estimated values of assets acquired and liabilities assumed for the September 2014 acquisition (in thousands):

Purchase Price
Consideration Given:
Cash	$	71,187
Assignment of oil and natural gas properties		35,918
Liabilities assumed, net		1,121
Total	$	108,226
Allocation of Purchase Price:
Proved oil and natural gas properties	$	48,997
Unproved oil and natural gas properties		59,083
Liabilities released		146
Total fair value of oil and natural gas properties	$	108,226

Pro Forma Operating Results

In accordance with ASC Topic 805, presented below are unaudited pro forma results for the three and nine months ended September 30, 2014 to show the effect on our consolidated results of operations as if the September 2014 acquisition had occurred on January 1, 2013.

The pro forma results reflect the results of combining our statement of operations with the results of operations from the oil and natural gas properties acquired in September 2014, adjusted for (i) the assumption of asset retirement obligations and accretion expense for the properties acquired and (ii) depletion expense applied to the adjusted basis of the properties acquired. The pro forma information is based upon these assumptions and is not necessarily indicative of future results of operations:

	Three Months Ended September 30, 2014		Nine Months Ended September 30, 2014
Revenues	$	43,160,959	$	95,151,146
Net Income	$	14,860,956	$	14,723,060
Net Income Per Share – Basic	$	4.47	$	4.44
Net Income Per Share – Diluted	$	3.36	$	3.60
Weighted Average Shares Outstanding – Basic	$	3,324,970	$	3,316,470
Weighted Average Shares Outstanding – Diluted	$	4,419,020	$	4,093,377

XML

ASSET RETIREMENT OBLIGATION (Narrative) (Details)	9 Months Ended
	Sep. 30, 2015 USD ($)
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	$ 0

XML

LIQUIDITY AND CAPITAL RESOURCES (Narrative) (Details) - USD ($)	Nov. 06, 2015	Oct. 06, 2015	Sep. 30, 2015
Liquidity and Capital Resources [Abstract]
Cash available			$ 5,100,000
Remaining amount available under credit facility			40,000,000
Credit facility outstanding balance			$ 160,000,000
Line Of Credit Facility [Line Items]
Line of credit facility, excess of amount outstanding over borrowing base	$ 19,600,000
Prior to Scheduled Semi-Annual Lender Redetermination [Member]
Line Of Credit Facility [Line Items]
Current borrowing base under credit facility		$ 200,000,000
Subsequent to Scheduled Semi-Annual Lender Redetermination [Member]
Line Of Credit Facility [Line Items]
Current borrowing base under credit facility		$ 120,000,000

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BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES (Narrative) (Details)		3 Months Ended		9 Months Ended
	May. 20, 2015 shares	Sep. 30, 2015 USD ($) $ / shares shares	Sep. 30, 2014 USD ($)	Sep. 30, 2015 USD ($) $ / shares shares	Sep. 30, 2014 USD ($)	Dec. 31, 2014 USD ($) $ / shares shares	Jul. 10, 2013 shares	Oct. 22, 2012 shares	May. 27, 2011 shares
Reverse Stock Split
Reverse Stock split (in Ratio)	.05
Effect of Reverse Stock Split on Common Stock Underlying Outstanding Convertible Securities [Line Items]
Reverse stock split, reduction in shares (in Shares)	(105,274,000)
Cash and Cash Equivalents
Cash FDIC insured amount | $		$ 250,000		$ 250,000
Restricted Cash
Restricted cash and cash equivalents, current and non-current | $		0		0		$ 4,000,000
Full Cost Method
Internal salaries capitalized | $		814,011	$ 1,354,556	3,245,667	$ 4,278,105
Stock-based compensation included in internal salaries capitalized | $		78,390	624,629	708,600	2,020,992
Capitalized interest | $		0	$ 0	0	0
Amount related to expiring leases included in the costs subject to depletion calculation | $				15,231,547	$ 2,979,258
Unamortized costs of oil and gas properties exceeding the ceiling test limit | $				158,278,000
Impairment of oil and natural gas properties | $		$ 158,278,000		$ 304,903,000
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of options outstanding (in Shares)		40,536		40,536		59,746
Income Taxes
Number of uncertain tax positions (in Integer) | $ / shares		0		0		0
Uncertain tax liabilities recorded in balance sheet | $		$ 0		$ 0		$ 0
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Convertible debt | $						$ 151,500,000
Industry Segment and Geographic Information
Number of reportable segments (in Integer) | $ / shares				1
Number of long lived assets located outside the United States (in Integer) | $ / shares		0		0
Common Shares Underlyng Outstanding Warrants [Member]
Effect of Reverse Stock Split on Common Stock Underlying Outstanding Convertible Securities [Line Items]
Reverse stock split, reduction in shares (in Shares)	(5,919,000)
Common Shares Underlyng Outstanding Options [Member]
Effect of Reverse Stock Split on Common Stock Underlying Outstanding Convertible Securities [Line Items]
Reverse stock split, reduction in shares (in Shares)	(955,000)
Common Shares Underlying Outstanding 2% Convertible Notes Due 2019 [Member]
Effect of Reverse Stock Split on Common Stock Underlying Outstanding Convertible Securities [Line Items]
Reverse stock split, reduction in shares (in Shares)	(16,402,000)
Minimum [Member]
Non oil and gas property and equipment [Line items]
Useful life (in Duration)				3 years
Maximum [Member]
Non oil and gas property and equipment [Line items]
Useful life (in Duration)				7 years
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 authorized for issuance (in Shares)									35,714
Stock-based compensation, equity incentive plan, shares available for issuance (in Shares)		567,113		567,113
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)		42,491		42,491
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)		380,396		380,396
2011 Equity Incentive Plan (the "2011 Plan") [Member] | Nonvested Restricted Stock Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Nonoption units outstanding (in Shares)		72,092		72,092
2011 Equity Incentive Plan - October 22, 2012 Amendment [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation, equity incentive plan, shares authorized for issuance (in Shares)								175,000
2011 Equity Incentive Plan - July 10, 2013 Amendment [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation, equity incentive plan, shares authorized for issuance (in Shares)							490,000
2011 Equity Incentive Plan - May 20, 2015 Amendment [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation, equity incentive plan, shares authorized for issuance (in Shares)	990,000
Nonvested 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)				72,092
Exercisable Stock Options [Member]
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Anti-dilutive securities excluded from computation of earnings per share (in Shares)				30,759
Non Exercisable Stock Options [Member]
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Anti-dilutive securities excluded from computation of earnings per share (in Shares)				9,777
Warrants Exercisable at $9.52 [Member]
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Anti-dilutive securities excluded from computation of earnings per share (in Shares)				255,732
Warrant exercise price | $ / shares		$ 9.52		$ 9.52
Warrants Exercisable at $137.20 [Member]
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Anti-dilutive securities excluded from computation of earnings per share (in Shares)				11,165
Warrant exercise price | $ / shares		137.20		$ 137.20
Warrants Exercisable at $994.00 [Member]
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Anti-dilutive securities excluded from computation of earnings per share (in Shares)				44,643
Warrant exercise price | $ / shares		$ 994.00		$ 994.00
Convertible Senior 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)				863,248
Convertible debt | $		$ 151,500,000		$ 151,500,000

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ASSET RETIREMENT OBLIGATION (Schedule of Change in Asset Retirement Obligation) (Details) - USD ($)	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Asset Retirement Obligation [Abstract]
Beginning Asset Retirement Obligation			$ 2,671,975	$ 692,137	$ 692,137
Revision of previous estimate					148,968
Liabilities Incurred or Acquired			$ 440,536		1,817,939
Accretion of Discount on Asset Retirement Obligations	$ 52,500	$ 28,037	$ 153,007	$ 63,837	104,803
Wells Settled through P&A					(72,555)
Liabilities Associated with Properties Sold					(19,317)
Ending Asset Retirement Obligation	$ 3,265,518		$ 3,265,518		$ 2,671,975

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OIL AND NATURAL GAS PROPERTIES (Narrative) (Details)			9 Months Ended
	Jul. 31, 2015 USD ($) $ / shares	Sep. 02, 2014 USD ($) $ / shares	Sep. 30, 2015 USD ($)	Sep. 30, 2014 USD ($)
Oil and Gas in Process Activities [Line Items]
Total proceeds from sale of working interest				$ 36,155,859
McKenzie County, North Dakota [Member]
Oil and Gas in Process Activities [Line Items]
Working interest percentage sold (in Percent)	30.00%
Amount of acreage in working interest sold (in Acres) | $ / shares	25,000
Recent drilling costs reimbursement received in working interest sale	$ 5,400,000
Richland County, Montana [Member]
Oil and Gas in Process Activities [Line Items]
Amount of acreage in working interest sold (in Acres) | $ / shares	4,400
McKenzie County, North Dakota and Richland County, Montana [Member]
Oil and Gas in Process Activities [Line Items]
Cash purchase price proceeds from working interest sale	$ 17,400,000
Total proceeds from sale of working interest	$ 22,800,000
McKenzie Billings and Dunn Counties, North Dakota [Member]
Oil and Gas in Process Activities [Line Items]
Number of acres acquired (in Acres) | $ / shares		30,500
Cash portion of purchase price of acquired oil and natural gas property leases		$ 71,200,000
Williams County, North Dakota [Member]
Oil and Gas in Process Activities [Line Items]
Acreage assigned portion of purchase price of acquired oil and gas acreage (in Acres) | $ / shares		4,300

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OIL AND NATURAL GAS PROPERTIES (Schedule of Purchase Price of Acquisition Assets Acquired and Liabilities Assumed) (Details)	Sep. 02, 2014 USD ($)
Oil and Natural Gas Properties [Abstract]
Cash	$ 71,187
Assignment of oil and natural gas properties	35,918
Liabilities assumed, net	1,121
Total	108,226
Proved oil and natural gas properties	48,997
Unproved oil and natural gas properties	59,083
Liabilites released	146
Total fair value of oil and natural gas properties	$ 108,226

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LIQUIDITY AND CAPITAL RESOURCES

9 Months Ended

Sep. 30, 2015

Liquidity and Capital Resources [Abstract]

LIQUIDITY AND CAPITAL RESOURCES

NOTE 3 LIQUIDITY AND CAPITAL RESOURCES

As of September 30, 2015, the Company had available cash of approximately $5.1 million, availability under its reserve-based revolving credit facility (the “Credit Facility”) with Wells Fargo Bank, N.A., as administrative agent, and the lenders party thereto, of approximately $40.0 million, and had drawn approximately $160.0 million.  On October 6, 2015, the Company’s borrowing base under its Credit Facility was decreased from $200 million to $120 million as part of the Company’s regularly scheduled semi-annual redetermination by its lender. The decrease in the borrowing base has resulted in the outstanding revolving credit facility balance exceeding the revised borrowing base by approximately $19.6 million as of November 6, 2015. Under the terms of the Credit Agreement, the Company is obligated to repay the deficiency in three monthly installments following the date of the redetermination. The Company does not expect to be able to make the monthly installments, which will result in a default under the Credit Agreement. Further, the previously announced term loan facility was not consummated and has had an adverse effect on the Company’s operations and liquidity. The Company and its advisors are negotiating with the bank group regarding a repayment schedule and continues to work with a group of term debt providers for a term debt solution. The Company believes it will need to complete certain transactions, including management of and/or refinancing of its debt capital structure and potential asset sales, to have sufficient liquidity to satisfy all of its obligations, including eliminating the approximate $19.6 million deficiency under the Credit Facility in the near term and obligations such as oil, natural gas and produced water transportation and processing commitments, fixed drilling commitments and operating leases, in the long term.

As a result of substantial declines in oil and gas prices during the latter half of 2014 and continuing into the first part of 2015, the liquidity outlook of the Company, including its working capital balance and EBITDA, has been impacted.  As a result, the Company expects lower operating cash flows than previously experienced and if commodity prices continue to remain low, the Company’s liquidity will be further impacted. In addition to the default regarding the deficiency repayments under the Credit Agreement described above, the Company was not in compliance with the total debt to EBITDA and Senior Secured Debt-to-EBITDA ratios under the Credit Facility as of September 30, 2015. The breach of the covenants under the Credit Facility could cause a default under the Credit Facility if not amended or waived by the lending group, and the lenders would be able to accelerate the maturity of the Credit Facility and exercise other rights and remedies. This, in turn, would cause a default under the Convertible Notes due in 2019 and permit the holders of those notes to accelerate their maturity. In accordance with the provisions under ASC 470-10-45-1, the Company has classified the balances of the Credit Facility and Convertible Notes as a current liability as of September 30, 2015. Furthermore, the ability to refinance any of the existing indebtedness on commercially reasonable terms may be materially and adversely impacted by the current conditions in the energy industry and the Company’s financial condition.

On November 5, 2015, the Company and certain of its subsidiaries entered into a forbearance agreement (the “Forbearance Agreement”) with the lenders party to the Credit Agreement. Pursuant to the Forbearance Agreement, the Lenders and the Agent agreed to forbear from exercising their rights and remedies under the Credit Agreement until December 18, 2015 (the “Forbearance Period”) with respect to certain events of default under the Credit Agreement. For additional information regarding the Forbearance Agreement, see Note 15 Subsequent Events— Forbearance Agreement.

The commodity price decline has materially reduced the revenues that were generated from the sale of the Company’s oil and gas production volumes during that period, which, in turn, has negatively affected the Company’s working capital balance and EBITDA. The potential for future oil prices to remain at their current price levels for an extended period of time raises substantial doubt regarding the Company’s ability to continue as a going concern. For purposes of this discussion, the term “substantial doubt” refers to concerns that a company may not be able to meet its obligations when they come due. The accompanying financial statements do not include any adjustments related to the recoverability and classification of recorded assets or the amounts and classification of liabilities, other than classifying the outstanding balances of the Credit Facility and Convertible Notes as current liabilities, that might result from the uncertainty associated with the ability to meet obligations as they come due.

The Company continues to pursue a number of actions including (i) actively managing the debt capital structure, (ii) selling additional assets, (iii) minimizing capital expenditures, (iv) obtaining waivers or amendments from lenders, (v) effectively managing working capital and (vi) improving cash flows from operations. As previously noted, the Company has engaged financial advisors and other professionals to assist it with reviewing all options to improve its liquidity profile and strengthen its balance sheet. These efforts continue in earnest and the Company is considering all available strategic alternatives and financing possibilities, including, without limitation, the incurrence of additional secured indebtedness and the exchange or refinancing of existing obligations.  The Company can provide no assurance that these discussions will result in the completion of a transaction, or that any completed transaction will result in sufficient liquidity to satisfy the Company’s obligations.

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OIL AND NATURAL GAS PROPERTIES (Schedule of Pro Forma Results Of Acquisition) (Details) - USD ($)	3 Months Ended	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Oil and Natural Gas Properties [Abstract]
Revenues	$ 43,160,959	$ 95,151,146
Net Income	$ 14,860,956	$ 14,723,060
Net Income per Share - Basic (in Dollars per Share)	$ 4.47	$ 4.44
Net Income per Share - Diluted (in Dollars per Share)	$ 3.36	$ 3.60
Weighted Average Shares Outstanding - Basic (in Shares)	3,324,970	3,316,470
Weighted Average Shares Outstanding - Diluted (in Shares)	4,419,020	4,093,377

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STOCK OPTIONS AND WARRANTS (Schedule of Warrants Outstanding) (Details)	9 Months Ended
	Sep. 30, 2015 $ / shares shares	Dec. 31, 2013 $ / shares	Feb. 19, 2013 $ / shares
Class of Warrant or Right [Line Items]
Warrants outstanding (in Shares) | shares	311,540
Weighted-average exercise price of warrants outstanding (in Dollars per Unit)	9.52	16.45	115.40
Issued December 1, 2009 [Member]
Class of Warrant or Right [Line Items]
Warrants outstanding (in Shares) | shares	1,861
Weighted-average exercise price of warrants outstanding (in Dollars per Unit)	137.20
Expiration date of warrants outstanding (in Date)	Dec. 01, 2019
Issued December 31, 2009 [Member]
Class of Warrant or Right [Line Items]
Warrants outstanding (in Shares) | shares	9,304
Weighted-average exercise price of warrants outstanding (in Dollars per Unit)	137.20
Expiration date of warrants outstanding (in Date)	Dec. 31, 2019
Issued February 8, 2011 [Member]
Class of Warrant or Right [Line Items]
Warrants outstanding (in Shares) | shares	44,643
Weighted-average exercise price of warrants outstanding (in Dollars per Unit)	994.00
Expiration date of warrants outstanding (in Date)	Feb. 08, 2016
Issued February 19, 2013 [Member]
Class of Warrant or Right [Line Items]
Warrants outstanding (in Shares) | shares	255,732
Weighted-average exercise price of warrants outstanding (in Dollars per Unit)	9.52
Expiration date of warrants outstanding (in Date)	Dec. 31, 2019

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SUBSEQUENT EVENTS (Narrative) (Details) - Subsequent Event [Member] - USD ($)	Nov. 06, 2015	Nov. 04, 2015	Oct. 22, 2015	Oct. 06, 2015	Oct. 01, 2015
Subsequent Event [Line Items]
Joint venture agreement working interest sold (in Percent)					30.00%
Joint venture agreement acreage of working interest sale in McKenzie County, North Dakota (in Acres)					25,000
Joint venture agreement acreage of working interest sale in Richland County, Montana (in Acres)					4,400
Joint venture agreement sales price of working interest sold					$ 17,400,000
Joint venture agreement reimbursement by partner for proportionate share of recently drilled and uncompleted wells					5,400,000
Joint venture agreement working interest sale total cash proceeds					22,800,000
Balance of credit facility prior to reduction via proceeds from working interest sale					160,000,000
Balance of credit facility subsequent to reduction via proceeds from working interest sale					$ 139,600,000
Credit facility borrowing base prior to redetermination				$ 200,000,000
Credit facility borrowing base subsequent to redetermination				$ 120,000,000
Credit facility excess balance over borrowing base	$ 19,600,000
Lender forbearance agreement default condition on default of certain specified contracts		$ 5,000,000
Lender forbearance agreement required monthly interest payment annual percentage rate over Alternate Base Rate (in Percent)		1.75%
Lender forbearance agreement fee percentage of outstanding principal balance (in Percent)		0.50%
Lender forbearance agreement percentage of net cash proceeds received (as defined) required to be made as mandatory prepayments (in Percent)		$ 1.00
Lender forbearance agreement required minimum combined weekly balance of unrestricted cash and cash equivalents		1,000,000
Lender forbearance agreement limit on capital expenditures		$ 1,500,000
Debt conversion noteholder agreement to exchange principal due for common stock value of debt to be converted			$ 3,000,000
Debt conversion noteholder agreement to exchange principal due for common stock, discount to be applied to volume-weighted stock price over fifteen trading days, appriximately October 23, 2015 through November 12, 2015 (in Percent)			15.00%
Debt conversion noteholder agreement to exchange principal due for common stock, expected number of shares to be issued in conversion (in Shares)			880,000
Debt conversion noteholder agreement to exchange principal due for common stock estimated per share price of shares to be issued in exchange (In Dollars per Share)			$ 1.70
Debt conversion noteholder agreement to exchange principal due for common stock expected debt conversion expense to be recognized			$ 1,500,000
Debt conversion noteholder agreement to exchange principal due for common stock expected remaining aggregate principal of convertible notes after conversion			$ 148,500,000

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED) - USD ($)	Sep. 30, 2015	Dec. 31, 2014
CURRENT ASSETS
Cash and Cash Equivalents	$ 5,068,320	$ 12,389,230
Accounts Receivable - Oil and Natural Gas Sales	4,002,942	7,203,455
Accounts Receivable - Joint Interest Partners	8,370,512	31,842,464
Other Receivables	860,980	980,317
Prepaid Expenses and Other Current Assets	681,581	289,061
Fair Value of Commodity Derivatives	6,336,057	5,044,125
Total Current Assets	25,320,392	57,748,652
Oil and Natural Gas Properties, Full Cost Method, at cost:
Proved Oil and Natural Gas Properties	697,814,220	593,472,170
Unproved Oil and Natural Gas Properties	141,768,220	166,708,263
Equipment and Facilities	15,220,754	6,086,896
Other Property and Equipment	4,266,762	2,583,372
Total Property and Equipment	859,069,956	768,850,701
Less - Accumulated Depreciation, Depletion and Amortization	(486,650,786)	(149,703,417)
Total Property and Equipment, Net	$ 372,419,170	619,147,284
Restricted Cash		4,000,000
Fair Value of Commodity Derivatives	$ 1,375,070
Debt Issuance Costs, Net of Amortization	$ 4,183,174	5,779,125
Deposits on Acquisitions		140,173
Deferred Tax Assets, Net	$ 1,813,561	1,813,796
Other Non-Current Assets	329,572	430,846
Total Assets	405,440,939	689,059,876
CURRENT LIABILITIES
Accounts Payable	38,762,753	$ 120,136,903
Revolving Credit Facility	159,683,000
Convertible Senior Notes	151,500,000
Accrued Expenses	5,073,975	$ 11,267,831
Advances from Joint Interest Partners	802,119	2,577,247
Deferred Tax Liability, Net	1,813,561	1,813,796
Total Current Liabilities	$ 357,635,408	135,795,777
LONG-TERM LIABILITIES
Revolving Credit Facility		75,000,000
Convertible Senior Notes		151,500,000
Asset Retirement Obligations	$ 3,265,518	2,671,975
Warrant Liability	$ 187,000	$ 2,199,000
Fair Value of Commodity Derivatives
Total Liabilities	$ 361,087,926	$ 367,166,752
COMMITMENTS AND CONTINGENCIES
Preferred Stock - Par Value $.001; 20,000,000 Shares Authorized;
Series B Voting Preferred Stock – 255,732 issued and outstanding at September 30, 2015 and December 31, 2014. Liquidation preference value of $256 as of September 30, 2015 and December 31, 2014.	$ 256	$ 256
STOCKHOLDERS' EQUITY
Common Stock, Par Value $.001; 500,000,000 Shares Authorized, 8,708,499 and 3,891,431 Shares Issued and Outstanding, respectively	8,709	3,891
Additional Paid-In Capital	507,612,218	455,087,277
Accumulated Deficit	(463,268,170)	(133,198,300)
Total Stockholders' Equity	44,352,757	321,892,868
Total Liabilities and Stockholders' Equity	$ 405,440,939	$ 689,059,876

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INCOME TAXES (Narrative) (Details) - USD ($)	9 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Income Taxes [Abstract]
Deferred income tax provision or benefit	$ 0	$ 0
Unrecognized tax benefits	$ 0	$ 0

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ORGANIZATION AND NATURE OF BUSINESS

9 Months Ended

Sep. 30, 2015

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 focused on acquiring acreage and developing oil and natural gas wells in the Williston Basin of North Dakota and Montana. The Company designs, drills and operates oil and natural gas wells on acreage where it holds a controlling working interest. The Company also participates in the drilling of oil and natural gas wells operated by other companies.

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PREFERRED AND COMMON STOCK (Schedule of Components of Preferred Stock Transaction) (Details) - USD ($)	Sep. 30, 2015	Dec. 31, 2014	Feb. 19, 2013
Total	$ 187,256	$ 2,199,256	$ 49,995,256
Series A Perpetual Preferred Stock [Member]
Total			41,369,000
Series B Voting Preferred Stock [Member]
Total	$ 256	$ 256	256
Warrant Liability [Member]
Total	$ 187,000	$ 2,199,000	$ 8,626,000

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OIL AND NATURAL GAS PROPERTIES (Tables)

9 Months Ended

Sep. 30, 2015

Oil and Natural Gas Properties [Abstract]

Schedule of Purchase Price of Acquisition, Assets Acquired and Liabilities Assumed

The following table summarizes the purchase price and estimated values of assets acquired and liabilities assumed for the September 2014 acquisition (in thousands):

Purchase Price
Consideration Given:
Cash	$	71,187
Assignment of oil and natural gas properties		35,918
Liabilities assumed, net		1,121
Total	$	108,226
Allocation of Purchase Price:
Proved oil and natural gas properties	$	48,997
Unproved oil and natural gas properties		59,083
Liabilities released		146
Total fair value of oil and natural gas properties	$	108,226

Schedule of Pro Forma Operating Results

Pro Forma Operating Results

In accordance with ASC Topic 805, presented below are unaudited pro forma results for the three and nine months ended September 30, 2014 to show the effect on our consolidated results of operations as if the September 2014 acquisition had occurred on January 1, 2013.

The pro forma results reflect the results of combining our statement of operations with the results of operations from the oil and natural gas properties acquired in September 2014, adjusted for (i) the assumption of asset retirement obligations and accretion expense for the properties acquired and (ii) depletion expense applied to the adjusted basis of the properties acquired. The pro forma information is based upon these assumptions and is not necessarily indicative of future results of operations:

	Three Months Ended September 30, 2014		Nine Months Ended September 30, 2014
Revenues	$	43,160,959	$	95,151,146
Net Income	$	14,860,956	$	14,723,060
Net Income Per Share – Basic	$	4.47	$	4.44
Net Income Per Share – Diluted	$	3.36	$	3.60
Weighted Average Shares Outstanding – Basic	$	3,324,970	$	3,316,470
Weighted Average Shares Outstanding – Diluted	$	4,419,020	$	4,093,377

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PREFERRED AND COMMON STOCK (Schedule of Restricted Stock Units and Restricted Stock Shares Outstanding) (Details) - Restricted Stock and Restricted Stock Units [Member]	9 Months Ended
	Sep. 30, 2015 $ / shares 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) | shares	29,231
Restricted stock units and restricted stock shares, Granted (in Shares) | shares	52,217
Restricted stock units and restricted stock shares, Canceled (in Shares) | shares	(3,691)
Restricted stock units and restricted stock shares, Vested and forfeited for taxes (in Shares) | shares	(1,358)
Restricted stock units and restricted stock shares, Vested and issued (in Shares) | shares	(4,037)
Non-vested restricted stock and restricted stock units, at end of period (in Shares) | shares	72,092
Non-vested restricted stock units, Weighted Average Grant Date Fair Value, at beginning of period (in Dollars per Share)	$ 145.40
Non-vested restricted stock units, Weighted Average Grant Date Fair Value, Granted (in Dollars per Share)	15.50
Non-vested restricted stock units, Weighted Average Grant Date Fair Value, Canceled (in Dollars per Share)	14.33
Non-vested restricted stock units, Weighted Average Grant Date Fair Value, Vested and forfeited for taxes (in Dollars per Share)	149.60
Non-vested restricted stock units, Weighted Average Grant Date Fair Value, Vested and issued (in Dollars per Share)	149.60
Non-vested restricted stock units, Weighted Average Grant Date Fair Value, at end of period (in Dollars per Share)	$ 57.78

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STOCK OPTIONS AND WARRANTS (Tables)

9 Months Ended

Sep. 30, 2015

Stock Options and Warrants [Abstract]

Schedule of Stock Options Outstanding Roll Forward

A summary of the stock options activity during the nine months ended September 30, 2015 is as follows:

	Number of Options			Weighted Average Exercise Price
Balance outstanding at January 1, 2015		59,746		$	171.20
Granted		—			—
Canceled		(19,210	)		218.39
Exercised		—			—
Balance outstanding at September 30, 2015		40,536		$	148.78
Options exercisable at September 30, 2015		30,759		$	150.83

Schedule of Stock Options Outstanding

At September 30, 2015, 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
2015		—		—		—		—		—		—
2014		15,781		3.18	$	143.48		8,804		2.98	$	145.17
2013		8,755		3.36		140.95		5,955		2.92		139.27
2012		14,731		1.82		156.80		14,731		1.82		156.80
Prior		1,269		2.97		174.96		1,269		2.97		174.96
Total		40,536		2.72	$	148.78		30,759		2.41	$	150.83

Schedule of Warrants Outstanding

The table below reflects the status of warrants outstanding at September 30, 2015:

	Warrants		Exercise Price		Expiration Date
December 1, 2009		1,861	$	137.20	December 1, 2019
December 31, 2009		9,304	$	137.20	December 31, 2019
February 8, 2011		44,643	$	994.00	February 8, 2016
February 19, 2013		255,732	$	9.52	December 31, 2019
Total		311,540

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BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES

9 Months Ended

Sep. 30, 2015

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 September 30, 2015 and for the three and nine months ended September 30, 2015 and 2014 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 condensed consolidated financial statements as of September 30, 2015 and for the three and nine months ended September 30, 2015 and 2014.

Interim financial results should be read in conjunction with the audited financial statements and footnotes for the year ended December 31, 2014, which were included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2014.

Reverse Stock Split

On May 20, 2015, a majority of the Company’s stockholders approved a 1-for-20 reverse stock split pursuant to which all stockholders of record received one share of common stock for each twenty shares of common stock owned (subject to minor adjustments as a result of fractional shares), which the Company’s board of directors had previously authorized.. This reverse stock split decreased the issued and outstanding shares of common stock by approximately 105,274,000 shares, the number of shares of common stock underlying outstanding warrants by approximately 5,919,000 shares, outstanding stock options by approximately 955,000 shares and the number of shares of common stock underlying the outstanding 2.0% Convertible Senior Notes due 2019 (the “Convertible Notes”) by 16,402,000 shares. GAAP requires that the reverse stock split be applied retrospectively to all periods presented. As a result, all shares of common and preferred stock, warrants and stock options, as well as any other common stock derivatives, described herein have been adjusted to reflect the 1-for-20 reverse stock split.

Cash and Cash Equivalents

The Company considers highly liquid investments with insignificant interest rate risk and original maturities of three months or less to be cash equivalents. Cash equivalents consist primarily of interest-bearing bank accounts and money market funds. The Company’s cash positions represent assets held in checking and money market accounts. These assets are generally available to the Company on a daily or weekly basis and are highly liquid in nature. Due to the balances being greater than their $250,000 insurance coverage, the Company does not have FDIC coverage on the entire amount of its bank deposits. The Company believes this risk to be minimal. In addition, the Company is subject to Security Investor Protection Corporation protection on a vast majority of its financial assets in the event one of the brokerage firms that the Company utilizes for its investments fails.

Restricted Cash

Restricted cash included in current and long-term assets on the condensed consolidated balance sheets totaled $0 and $4 million at September 30, 2015 and December 31, 2014, respectively.  At December 31, 2014, the balance related to a drilling commitment agreement entered into pursuant to oil and natural gas leases. The commitment was fulfilled and funds released during the three months ended September 30, 2015.

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 nine months ended September 30, 2015 and 2014.

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 September 30, 2015 and 2014, the Company capitalized $814,011 and $1,354,556, respectively, of internal salaries, which included $78,390 and $624,629, respectively, of stock-based compensation. For the nine months ended September 30, 2015 and 2014, the Company capitalized $3,245,667 and $4,278,105, respectively, of internal salaries, which included $708,600, and $2,020,992, 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 nine months ended September 30, 2015 and 2014.

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 nine months ended September 30, 2015 and 2014. 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 nine months ended September 30, 2015 and the year ended December 31, 2014, the Company included $15,231,547 and $2,979,258, 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. Any required write-downs are included in the consolidated statement of operations as an impairment charge. Based on calculated reserves at September 30, 2015, the unamortized costs of the Company’s oil and natural gas properties exceeded the ceiling test limit by $158,278,000. As a result, the Company was required to record impairments of the net capitalized costs of its oil and natural gas properties in the amount of $158,278,000 and $304,903,000 for the three and nine months ended September 30, 2015, respectively. As of September 30, 2014, the unamortized costs of the Company’s oil and natural gas properties did not exceed the ceiling test limit and no impairment expense was recognized for the three and nine months ended September 30, 2014.

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 it can be reasonably estimated 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 September 30, 2015 and December 31, 2014, 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 of peer company data fairly represents the expected volatility it would experience if it were in the oil and natural gas industry over the expected term of the options. The Company used the simplified method to determine the expected term of the options due to the lack of historical data. Changes in these assumptions can materially affect the fair value estimate.

On May 27, 2011, the stockholders of the Company approved the 2011 Equity Incentive Plan (the “2011 Plan”), under which 35,714 shares of common stock were reserved. On October 22, 2012, 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 175,000 shares. On July 10, 2013, the stockholders of the Company approved an amendment to the 2011 Plan to increase the number of shares authorized for issuance under the 2011 Plan to 490,000 shares. On May 20, 2015, the stockholders of the Company approved an amendment to the 2011 Plan to increase the number of shares authorized for issuance under the 2011 Plan to 990,000 shares. The purpose of the 2011 Plan is to promote the success of the Company and its affiliates by facilitating the employment and retention of competent personnel and by furnishing incentives to those officers, directors and employees upon whose efforts the success of the Company and its affiliates will depend to a large degree. It is the intention of the Company to carry out the 2011 Plan through the granting of incentive stock options, nonqualified stock options, restricted stock awards, restricted stock unit awards, performance awards and stock appreciation rights. As of September 30, 2015, 42,491 stock options and 380,396 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 72,092 nonvested restricted stock units. As of September 30, 2015, there were 567,113 shares available for issuance under the 2011 Plan.

Income Taxes

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

The tax effects from an uncertain tax position can be recognized in the financial statements only if the position is more likely than not of being sustained if the position were to be challenged by a taxing authority. The Company has examined the tax positions taken in its tax returns and determined that there are no uncertain tax positions. As a result, the Company has recorded no uncertain tax liabilities in its condensed 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 shares of common stock outstanding during the period. Diluted earnings per share are computed using the weighted average number of shares of common stock 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 nine months ended September 30, 2015 and 2014, the potentially dilutive shares were anti-dilutive and were thus not included in the net loss per share calculation.

As of September 30, 2015, (i) 72,092 nonvested restricted stock units were issued and outstanding and represent potentially dilutive shares; (ii) 30,759 stock options were issued and presently exercisable and represent potentially dilutive shares; (iii) 9,777 stock options were granted but were not presently exercisable and represent potentially dilutive shares; (iv) 255,732 warrants were issued and presently exercisable, which have an exercise price of $9.52 and represent potentially dilutive shares; (v) 11,165 warrants were issued and presently exercisable, which have an exercise price of $137.20 and represent potentially dilutive shares; (vi) 44,643 warrants were issued and presently exercisable, which have an exercise price of $994.00 and represent potentially dilutive shares; and (vii) $151.5 million of Convertible Notes were convertible into approximately 863,248 shares of common stock as of September 30, 2015 and represent 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’ creditworthiness, the Company’s creditworthiness, 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 marketplace participant’s view. Management believes that this approach provides a reasonable, non-biased, verifiable, and consistent methodology for valuing commodity derivative instruments (see Note 13 – Derivative Instruments and Price Risk Management).

Warrant Liability

From time to time, the Company may have financial instruments such as warrants that may be classified as liabilities when either (a) the holders possess rights to net cash settlement, (b) physical or net equity settlement is not in the Company’s control, or (c) the instruments contain other provisions that cause 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 6 – Preferred and Common Stock), the Company issued warrants that contain a put and other liability type provisions. Accordingly, these warrants are accounted for as a liability. This warrant liability is accounted for at fair value with changes in fair value reported in the consolidated statement 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, valuation of asset retirement obligations 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 ($)	Sep. 30, 2015	Dec. 31, 2014
LIABILITIES AND STOCKHOLDERS' EQUITY
Preferred Stock - Par Value (in Dollars per Share)	$ .001	$ 0.001
Preferred Stock - Shares Authorized (in Shares)	20,000,000	20,000,000
Preferred Stock - Shares Issued (in Shares)	255,732	255,732
Preferred stock - Shares Outstanding (in Shares)	255,732	255,732
Preferred Stock - Liquidation Preference Value	$ 256	$ 256
STOCKHOLDERS' EQUITY
Common Stock, Par Value (in Dollars per Share)	$ .001	$ 0.001
Common Stock, Shares Authorized (in Shares)	500,000,000	500,000,000
Common Stock, Shares Issued (in Shares)	8,708,499	3,891,431
Common Stock, Shares Outstanding (in Shares)	8,708,499	3,891,431

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FAIR VALUE

9 Months Ended

Sep. 30, 2015

Fair Value [Abstract]

FAIR VALUE

NOTE 12 FAIR VALUE

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

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

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

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

The level in the fair value hierarchy within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The Company’s policy is to recognize transfer in and/or out of the 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 September 30, 2015:

	Fair Value Measurements at September 30, 2015 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	$	—	$	—		$	(187,000	)
Commodity Derivatives – Current Asset (oil puts)		—		14,310,070			—
Commodity Derivatives – Non Current Asset (oil puts)		—		3,442,664			—
Commodity Derivatives – Current Liability (oil put premiums)		—		(7,974,013	)		—
Commodity Derivatives – Long Term Liability (oil put premiums)		—		(2,067,594	)		—
Total	$	—	$	7,711,127		$	(187,000	)

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, 2014:

	Fair Value Measurements at December 31, 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 Asset (Liability)	$	—	$	—	$	(2,199,000	)
Commodity Derivatives – Current Asset (oil swaps)		—		5,044,125		—
Total	$	—	$	5,044,125	$	(2,199,000	)

Level 2 assets consist of commodity derivative assets and liabilities (see Note 13 – Derivative Instruments and Price Risk Management). The fair value of the commodity derivative assets and liabilities are estimated by the Company using the income valuation techniques utilizing an option pricing or discounted cash flow model, as appropriate, that takes 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 condensed consolidated balance sheets.

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

Balance, at January 1, 2014	$	(15,703,000	)
Change in Fair Value of Warrant Liability		13,504,000
Balance, at December 31, 2014		(2,199,000	)
Change in Fair Value of Warrant Liability		2,012,000
Balance, at September 30, 2015	$	(187,000	)

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 gain was $221,000 and $216,000 for the three months ended September 30, 2015 and 2014, respectively, and $2,012,000 and $(1,751,000) for the nine months ended September 30, 2015 and 2014, respectively. The warrant revaluation gain (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 13 – Derivative Instruments and Price Risk Management.

Nonrecurring Fair Value Measurements

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

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

The Company’s non-derivative financial instruments include cash and cash equivalents, restricted cash, 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 $39.4 million at September 30, 2015 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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Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2015	Nov. 06, 2015
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	Sep. 30, 2015
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock Shares Outstanding		8,708,499
Entity Well Known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Voluntary Filer	No

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DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT

9 Months Ended

Sep. 30, 2015

Derivative Instruments and Price Risk Management [Abstract]

DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT

NOTE 13 DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT

Commodity Price Risk

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, both the current asset and liability and the non-current asset and liability are netted on the condensed consolidated balance sheet.

On January 5, 2015, the Company settled its outstanding NYMEX West Texas Intermediate oil derivative swap contracts on a total of 120,000 barrels of oil, resulting in the receipt of $5,317,300 in cash. On April 7, 2015, the Company entered into put option contracts for oil volumes produced in May 2015 through December 2016, whereby premiums are paid monthly throughout the life of the contracts. Open contracts as of September 30, 2015 are provided in the table below.

Settlement Period	Daily Volume Oil (Bbls)		Put Option Fixed Price Per Bbl		Total Volume (Bbls)		Premium Paid Per Bbl		Total Premiums Due
October 2015 – December 2015		4,000	$	55.00		368,000	$	4.88	$	1,795,840
January 2016 – December 2016		3,000	$	60.00		1,098,000	$	7.54	$	8,278,920

The following table sets forth a reconciliation of the changes in fair value of the Company’s commodity derivatives for the three and nine months ended September 30, 2015 and 2014.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Beginning fair value of commodity derivatives	$	(3,633,216	)	$	(5,852,801	)	$	5,044,125		$	(853,005	)
Total gains on commodity derivatives		12,699,147			11,184,716			8,148,386			3,722,780
Cash settlements (received) paid on commodity derivatives		(1,354,804	)		313,451			(5,481,384	)		2,775,591
Ending fair value of commodity derivatives	$	7,711,127		$	5,645,366		$	7,711,127		$	5,645,366

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 its counterparties that provide for offsetting payables against receivables from separate derivative instruments.

Warrant Liability

The warrants issued to White Deer Energy are classified as liabilities on the consolidated balance sheets because the warrants contain a contingent put and other liability type provisions (see Note 6 – Preferred and Common Stock). The shares of common stock 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 condensed consolidated statements of operations.

The Company estimated the value of the warrants issued on the date of issuance to be $8,626,000, or $33.80 per warrant, using the Monte Carlo model with the following assumptions: a term of 1,798 trading days, exercise price of $115.40, volatility rate of 40%, and a risk-free interest rate of 1.38%. The Company remeasured the warrants as of September 30, 2015, using a Black-Scholes model with the following assumptions: a term of 1,067 trading days, exercise price of $9.52, a 15-day volume weighted average stock price of $2.34, volatility rate of 80%, and a risk-free interest rate of 1.65%. As of September 30, 2015, the fair value of the warrants was $187,000, and was recorded as a liability on the accompanying condensed consolidated balance sheet. 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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CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
REVENUES
Oil Sales	$ 17,350,524	$ 28,266,332	$ 52,981,871	$ 76,989,268
Natural Gas Sales	494,804	460,857	1,224,667	2,061,201
Net Gains on Commodity Derivatives	12,699,147	11,184,716	8,148,386	3,722,780
Total Revenues	30,544,475	39,911,905	62,354,924	82,773,249
OPERATING EXPENSES
Production Expenses	8,201,949	6,962,450	25,972,453	13,477,176
Production Taxes	1,653,989	3,142,998	5,488,364	8,632,608
General and Administrative Expenses	3,821,473	5,483,655	12,495,471	21,609,218
Depletion of Oil and Natural Gas Properties	11,242,324	$ 9,193,566	31,622,386	$ 24,071,676
Impairment of Oil and Natural Gas Properties	158,278,000		304,903,000
Depreciation and Amortization	232,350	$ 104,465	559,139	$ 251,722
Accretion of Discount on Asset Retirement Obligations	52,500	$ 28,037	153,007	$ 63,837
Standby Rig Expense	3,800,446		6,173,111
Total Operating Expenses	187,283,031	$ 24,915,171	387,366,931	$ 68,106,237
INCOME (LOSS) FROM OPERATIONS	(156,738,556)	14,996,734	(325,012,007)	14,667,012
OTHER INCOME (EXPENSE)
Interest Expense	(2,735,348)	(1,206,571)	(7,044,901)	(2,515,034)
Warrant revaluation gain (expense)	221,000	216,000	2,012,000	(1,751,000)
Other Income (Expense)	281	(347,088)	539	(343,041)
Total Other Expense, Net	(2,514,067)	(1,337,659)	(5,032,362)	(4,609,075)
INCOME (LOSS) BEFORE INCOME TAXES	$ (159,252,623)	$ 13,659,075	$ (330,044,369)	$ 10,057,937
INCOME TAX PROVISION
NET INCOME (LOSS)	$ (159,252,623)	$ 13,659,075	$ (330,044,369)	$ 10,057,937
Net Income (Loss) Per Common Share - Basic (in Dollars per Share)	$ (19.85)	$ 4.11	$ (52.10)	$ 3.03
Net Income (Loss) Per Common Share - Diluted (in Dollars per Share)	$ (19.85)	$ 3.29	$ (52.10)	$ 2.89
Weighted Average Shares Outstanding - Basic (in Shares)	8,021,992	3,324,970	6,334,549	3,316,751
Weighted Average Shares Outstanding - Diluted (in Shares)	8,021,992	4,419,020	6,334,549	4,093,377

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STOCK OPTIONS AND WARRANTS

9 Months Ended

Sep. 30, 2015

Stock Options and Warrants [Abstract]

STOCK OPTIONS AND WARRANTS

NOTE 7  STOCK OPTIONS AND WARRANTS

Stock Options

The Company granted no stock options during the nine months ended September 30, 2015.

The impact on the Company’s condensed consolidated statement of operations of stock-based compensation expense related to options granted for the three months ended September 30, 2015 and 2014 was $(15,200) and $337,809, respectively, net of forfeitures, cancellations and $0 tax. The impact on the Company’s condensed consolidated statement of operations of stock-based compensation expense related to options granted for the nine months ended September 30, 2015 and 2014 was $142,276 and $810,419, respectively, net of forfeitures, cancellations and $0 tax. The Company capitalized $(5,035), and $187,017 in compensation to oil and natural gas properties related to outstanding options for the three months ended September 30, 2015 and 2014, respectively, and $106,995 and $595,628  for the nine months ended September 30, 2015 and 2014, respectively. The Company had $183,140 of total unrecognized compensation cost related to nonvested stock options granted as of September 30, 2015. The remaining cost is expected to be recognized over a weighted-average period of 0.89 years. These estimates are subject to change based on a variety of future events that 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 nine months ended September 30, 2015 is as follows:

	Number of Options			Weighted Average Exercise Price
Balance outstanding at January 1, 2015		59,746		$	171.20
Granted		—			—
Canceled		(19,210	)		218.39
Exercised		—			—
Balance outstanding at September 30, 2015		40,536		$	148.78
Options exercisable at September 30, 2015		30,759		$	150.83

At September 30, 2015, 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
2015		—		—		—		—		—		—
2014		15,781		3.18	$	143.48		8,804		2.98	$	145.17
2013		8,755		3.36		140.95		5,955		2.92		139.27
2012		14,731		1.82		156.80		14,731		1.82		156.80
Prior		1,269		2.97		174.96		1,269		2.97		174.96
Total		40,536		2.72	$	148.78		30,759		2.41	$	150.83

Warrants

The table below reflects the status of warrants outstanding at September 30, 2015:

	Warrants		Exercise Price		Expiration Date
December 1, 2009		1,861	$	137.20	December 1, 2019
December 31, 2009		9,304	$	137.20	December 31, 2019
February 8, 2011		44,643	$	994.00	February 8, 2016
February 19, 2013		255,732	$	9.52	December 31, 2019
Total		311,540

No warrants expired or were forfeited during the nine months ended September 30, 2015. All of the compensation expense related to the applicable vested warrants issued to employees has been expensed by the Company prior to 2012. All warrants outstanding were exercisable at September 30, 2015. See Note 13 – Derivative Instruments and Price Risk Management for details on the treatment of the warrants issued on February 19, 2013.

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PREFERRED AND COMMON STOCK

9 Months Ended

Sep. 30, 2015

Preferred and Common Stock [Abstract]

PREFERRED AND COMMON STOCK

NOTE 6  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, 255,732 shares of Series B Preferred Stock and warrants to purchase an initial aggregate 255,732 shares of the Company’s common stock at an initial exercise price of $115.40 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 the $50,000,000 principal and redemption premiums of $6,250,000, and no shares of Series A Preferred Stock remained outstanding as of September 30, 2015. 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 nine months ended September 30, 2015 and 2014.

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 255,732 shares of common stock at an initial exercise price of $115.40 per share and surrendering an equal number of shares of Series B Preferred Stock to the Company. In December 2014, the Company issued 536,091 common shares below the initial warrant exercise price of $115.40 to extinguish $21,000,000 of its Convertible Notes. In February 2015, the Company completed a public offering of 1,357,955 shares of common stock at a price of $22.40 per share for total net proceeds of approximately $29.4 million. During April and May 2015, the Company issued an aggregate 2,460,045 shares of common stock through its at-the-market continuous offering program (“ATM program”) at an average price of $6.87 per share for total net proceeds of approximately $16.4 million. During September 2015, the Company issued an aggregate 848,961 shares of common stock through its ATM Program at an average price of $2.79 per share for total net proceeds of approximately $2.3 million. The sales were made pursuant to the terms of the equity distribution agreements dated April 2, 2015 between the Company and its sales agents. As a result of these issuances, the warrant exercise price was reduced from $16.45 to $9.52 per share pursuant to a formula provided in the original warrant agreement. See Note 9 – Convertible Notes for further discussion of the December 2014 conversion and Note 13 – Derivative Instruments and Price Risk Management – Warrant Liability for further discussion of the warrant liability valuation.

Upon a change of control or Liquidation Event, as defined in the Securities Purchase Agreement, White Deer Energy had the right to elect to receive from the Company, in exchange for all, but not less than all, securities issued pursuant to the Securities Purchase Agreement an additional cash payment necessary to achieve a minimum internal rate of return of 25% as calculated as defined. The calculation took into account all cash inflows from and cash outflows to White Deer Energy. Upon the final Series A Preferred Stock redemption on October 15, 2013, the minimum internal rate of return was achieved and no additional cash payment would be required to be paid to White Deer Energy upon a change of control or liquidation event.

The Company recorded the transaction by recognizing the fair value of the Series A Preferred Stock at $38,552,994 (net of offering costs of $2,816,006), Series B Preferred Stock at $5,000 and a warrant liability of $8,626,000 at time of issuance. The Company 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 were probable. The Company recognized all issuance discount accretion related to the redemptions of preferred stock by October 15, 2013. There was no issuance discount remaining as of September 30, 2015 or December 31, 2014.

A summary of the preferred stock transaction components as of September 30, 2015, December 31, 2014 and the issuance date is provided below:

	September 30, 2015		December 31, 2014		February 19, 2013 (issuance date)
Series A Preferred Stock	$	—	$	—	$	41,369,000
Series B Preferred Stock		256		256		256
Warrant Liability		187,000		2,199,000		8,626,000
Total	$	187,256	$	2,199,256	$	49,995,256

Equity Issuances

On February 11, 2015, the Company completed a public offering of 1,357,955 shares of common stock at a price of $22.40 per share for total net proceeds of approximately $29.4 million.

During April and May 2015, the Company issued shares of common stock through its ATM Program totaling 2,460,045 at an average price of $6.87 per share for total net proceeds of approximately $16.4 million.  During September 2015, the Company issued shares of common stock through its ATM Program totaling 848,961 at an average price of $2.79 per share for total net proceeds of approximately $2.3 million. These sales were made pursuant to the terms of the equity distribution agreement dated April 2, 2015 between the Company and its sales agents.

Restricted Stock Awards and Restricted Stock Unit Awards

The Company incurred compensation expense associated with restricted stock and restricted stock units granted of $438,346 and $2,480,352 for the three months ended September 30, 2015 and 2014, respectively, and $2,444,623 and $8,686,625 for the nine months ended September 30, 2015 and 2014, respectively. As of September 30, 2015, there were 72,092 non-vested restricted stock units and $975,865 of associated remaining unrecognized compensation expense, which is expected to be recognized over the weighted-average period of 0.70 years. The Company capitalized compensation expense associated with the restricted stock and restricted stock units of $83,425 and $437,612 to oil and natural gas properties for the three months ended September 30, 2015 and 2014, respectively, and $601,605 and $1,425,364 for the nine months ended September 30, 2015 and 2014, respectively.

A summary of the restricted stock units and restricted stock shares activity during the nine months ended September 30, 2015 is as follows:

	Number of Shares			Weighted Average Grant Date Fair Value
Non-vested restricted stock and restricted stock units at January 1, 2015		29,231		$	145.40
Granted		52,217			15.50
Canceled		(3,961	)		14.33
Vested and forfeited for taxes		(1,358	)		149.60
Vested and issued		(4,037	)		149.60
Non-vested restricted stock and restricted stock units at September 30, 2015		72,092		$	57.78

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PREFERRED AND COMMON STOCK (Tables)

9 Months Ended

Sep. 30, 2015

Preferred and Common Stock [Abstract]

Schedule of Components of Preferred Stock Transaction

A summary of the preferred stock transaction components as of September 30, 2015, December 31, 2014 and the issuance date is provided below:

	September 30, 2015		December 31, 2014		February 19, 2013 (issuance date)
Series A Preferred Stock	$	—	$	—	$	41,369,000
Series B Preferred Stock		256		256		256
Warrant Liability		187,000		2,199,000		8,626,000
Total	$	187,256	$	2,199,256	$	49,995,256

Schedule of Restricted Stock Units and Restricted Stock Shares Outstanding

A summary of the restricted stock units and restricted stock shares activity during the nine months ended September 30, 2015 is as follows:

	Number of Shares			Weighted Average Grant Date Fair Value
Non-vested restricted stock and restricted stock units at January 1, 2015		29,231		$	145.40
Granted		52,217			15.50
Canceled		(3,961	)		14.33
Vested and forfeited for taxes		(1,358	)		149.60
Vested and issued		(4,037	)		149.60
Non-vested restricted stock and restricted stock units at September 30, 2015		72,092		$	57.78

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COMMITMENTS AND CONTINGENCIES

9 Months Ended

Sep. 30, 2015

Commitments and Contingencies [Abstract]

COMMITMENTS AND CONTINGENCIES

NOTE 14 COMMITMENTS AND CONTINGENCIES

Executive Compensation

In January 2015, the Company determined that fifty percent of the earned cash bonuses for 2014 for the Chief Executive Officer and Vice Chairman of the Board of Directors would be paid in the form of equity and that such 50 percent (payable in the form of equity) would be paid by early 2016. Additionally, the Company determined that fifty percent of the annual equity bonus would be granted in early 2016.

After discussions with the Compensation Committee relating to the foregoing payments, each of the officers agreed in principle not to allege a violation of their respective employment agreements if the bonuses were paid in accordance with the foregoing.

Oil, Natural Gas and Produced Water Transportation and Processing Commitments. 

The Company has commitments for the transportation and processing of its production on certain wells within its operating area in the Williston Basin of North Dakota, including an aggregate minimum commitment to deliver on a gross basis 16.4 MMBbls of oil at a fee of $1.21/Bbl, 10.9 Bcf of natural gas at a fee of $1.67/Mcf and 28.2 MMBbls of produced water at a fee of $0.82/Bbl through April 2020. The Company is required to make monthly deficiency payments for any shortfalls in delivering the minimum volumes under these commitments. Currently, the Company has insufficient production to meet these contractual commitments. However, as the Company develops additional reserves, it anticipates exceeding its current minimum volume commitments and, therefore, intends to enter into additional transportation and processing commitments in the future. The commitment price can be adjusted in future years. These future transportation and processing commitments may expose the Company to additional volume deficiency payments. For the three months ended September 30, 2015, the Company incurred deficiency fees of $1.0 million and expects to continue to accrue deficiency fees under its commitments as long as the Company’s development program is suspended. The deficiency fees are included as production expenses in the statement of operations for the three and nine months ended September 30, 2015. Transportation costs aside from the deficiency fee are included in the realized price of oil and natural gas revenues in the statement of operations for the three and nine months ended September 30, 2015. Estimated future deficiency fees are included in the calculation of the present value of estimated future net revenues from proved oil and natural gas reserves, which impacts the ceiling test impairment calculation.

Other

The Company is involved in various matters incidental to its operations and business that might give rise to a loss contingency.  These matters may include legal and regulatory proceedings, commercial disputes, claims from royalty, working interest and surface owners, property damage and personal injury claims and environmental authorities or other matters. In addition, the Company may be subject to customary audits by governmental authorities regarding the payment and reporting of various taxes, governmental royalties and fees as well as compliance with unclaimed property (escheatment) requirements and other laws.  Further, other parties with an interest in wells operated by the Company have the ability under various contractual agreements to perform audits of its joint interest billing practices. The Company vigorously defends itself in these matters.  If the Company determines that an unfavorable outcome or loss of a particular matter is probable and the amount of the loss can be reasonably estimated, it accrues a liability for the contingent obligation. As new information becomes available or as a result of legal or administrative rulings in similar matters or a change in applicable law, the Company’s conclusions regarding the probability of outcomes and the amount of estimated loss, if any, may change. The impact of subsequent changes to the Company’s accruals could have a material effect on its results of operations.

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ASSET RETIREMENT OBLIGATION

9 Months Ended

Sep. 30, 2015

Asset Retirement Obligation [Abstract]

ASSET RETIREMENT OBLIGATION

NOTE 10  ASSET RETIREMENT OBLIGATION

The Company has asset retirement obligations associated with the future plugging and abandonment of its proved oil and natural gas properties and related facilities. Under the provisions of ASC 410-20-25, the fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred and can be reasonably estimated, 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) plugging and abandonment costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors (average of 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 nine months ended September 30, 2015 and the year ended December 31, 2014:

	Nine Months Ended September 30, 2015		Year Ended December 31, 2014
Beginning Asset Retirement Obligation	$	2,671,975	$	692,137
Revision of Previous Estimates		—		148,968
Liabilities Incurred or Acquired		440,536		1,817,939
Accretion of Discount on Asset Retirement Obligations		153,007		104,803
Wells Settled Through P&A		—		(72,555	)
Liabilities Associated with Properties Sold		—		(19,317	)
Ending Asset Retirement Obligation	$	3,265,518	$	2,671,975

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REVOLVING CREDIT FACILITY

9 Months Ended

Sep. 30, 2015

Revolving Credit Facility [Abstract]

REVOLVING CREDIT FACILITY

NOTE 8 REVOLVING CREDIT FACILITY

Wells Fargo Facility

On November 20, 2012, the Company entered into a senior secured revolving credit facility (as amended, the “Credit Facility”) with Wells Fargo Bank, N.A., as administrative agent (“Wells Fargo”), and the lenders party thereto. The Credit Facility is a senior secured reserve-based revolving credit facility with a maximum commitment of $400 million. On April 30, 2015, in connection with the semi-annual borrowing base redetermination, the Company and its lending group entered into an amendment to the Credit Facility. The amendment to the Credit Facility reduced the borrowing base from $250 million to $200 million. As of September 30, 2015, the Company had drawn approximately $160 million toward its $200 million borrowing base under the Credit Facility. The Company’s borrowing base under its Credit Facility was subject to its semi-annual redetermination on October 6, 2015, and the lenders decreased the borrowing base to $120 million. This redetermination resulted in an outstanding deficiency under the Credit Facility of approximately $19.6 million. Under the terms of the Credit Agreement, the Company is permitted to repay the deficiency in three monthly installments beginning 30 days after the date of the redetermination. The Company does not expect to be able to make the monthly installments, which will result in a default under the Credit Agreement. 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 5.0 to 1.0 for periods ending on March 31, 2015 through June 30, 2016 and 5.5 to 1.0 for periods ending September 30, 2016 through December 31, 2016 and (c) a Senior Secured Debt-to-EBITDA ratio for periods ending March 31, 2015 through December 31, 2016 of no more than 2.5 to 1.0. The Company was not in compliance with the total debt to EBITDA and Senior Secured Debt-to-EBITDA ratios under the Credit Facility as of September 30, 2015.

On November 5, 2015, the Company and certain of its subsidiaries entered into a Forbearance Agreement with the lenders party to the Credit Agreement. Pursuant to the Forbearance Agreement, the Lenders and the Agent agreed to forbear from exercising their rights and remedies under the Credit Agreement until December 18, 2015 with respect to certain events of defaults under the Credit Agreement. Please see Note 3 – Liquidity and Capital Resources and Note 15 – Subsequent Events – Forbearance Agreement for further information regarding changes to financing arrangements and changes to the Credit Facility subsequent to September 30, 2015.

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 under the Credit Facility, 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 September 30, 2015, the annual interest rate on the Credit Facility was 2.70%.

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 September 30, 2015, the Company has not obtained any letters of credit under the Credit 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 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. As of September 30, 2015, the Company had hedges covering 70% of its projected production through 2016.

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CONVERTIBLE NOTES

9 Months Ended

Sep. 30, 2015

Convertible Notes [Abstract]

CONVERTIBLE NOTES

NOTE 9 CONVERTIBLE NOTES

On March 24, 2014, the Company completed a private placement of $172.5 million in aggregate principal amount of 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. As of September 30, 2015, 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 had a total outstanding principal balance of $151.5 million and were convertible into approximately 863,248 shares of common stock.

The net proceeds from the Convertible Notes were $166.9 million, after deducting commissions and 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 5.698 shares of the Company’s common stock per $1,000 principal amount of Convertible Notes (which represents a conversion price of approximately $175.60 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, including the acceleration of the maturity of the Credit Facility, which would, in turn, cause a default under the Indenture and permit the holders of the Convertible Notes to accelerate their maturity. 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 under the Indenture as of September 30, 2015; however, the Company was not in compliance with all covenants under the Credit Facility, and the lenders thereunder could declare a default, which if remained uncured, would allow the lenders under the Credit Facility to accelerate the maturity of the amounts outstanding under the Credit Facility. As of September 30, 2015, the Company had drawn approximately $160 million toward its $200 million borrowing base under the Credit Facility. The Company’s borrowing base under its Credit Facility was subject to its semi-annual redetermination on October 6, 2015, and the lenders decreased the borrowing base to $120 million. This redetermination resulted in an outstanding deficiency under the Credit Facility of approximately $19.6 million. Under the terms of the Credit Agreement, the Company is permitted to repay the deficiency in three monthly installments beginning 30 days after the date of the redetermination. The Company does not expect to be able to make the monthly installments, which will result in a default under the Credit Agreement. In accordance with the provisions under ASC 470-10-45-1, the Company has classified the balance of the Convertible Notes as a current liability as of September 30, 2015. On November 5, 2015, the Company and certain of its subsidiaries entered into a Forbearance Agreement with the lenders party to the Credit Agreement. Pursuant to the Forbearance Agreement, the Lenders agreed to forbear from exercising their rights and remedies under the Credit Agreement until December 18, 2015 with respect to certain events of defaults under the Credit Agreement. For additional information regarding the Forbearance Agreement, see Note 15 Subsequent Events— Forbearance Agreement.

In December 2014, the Company issued 536,091 shares of common stock to extinguish $21,000,000 principal value of Convertible Notes. The Convertible Notes had 119,658 underlying shares of common stock under the terms of the Indenture. As a result, the Company recognized $10,438,080 of debt conversion expense for the year ended December 31, 2014 for the fair value of the shares of common stock issued in excess of the shares of common stock underlying the exchanged Convertible Notes. For details on the additional note conversion subsequent to September 30, 2015, see Note 15 – Subsequent Events – Debt Conversion.

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INCOME TAXES

9 Months Ended

Sep. 30, 2015

Income Taxes [Abstract]

INCOME TAXES

NOTE 11  INCOME TAXES

Deferred income tax assets and liabilities are determined based upon differences between the financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse. Accounting standards require the consideration of a valuation allowance for deferred tax assets if it is “more likely than not” that some component or all of the benefits of deferred tax assets will not be realized. As of September 30, 2015 and December 31, 2014, 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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PREFERRED AND COMMON STOCK (Narrative) (Details)		1 Months Ended			2 Months Ended	3 Months Ended		9 Months Ended		12 Months Ended
	Feb. 19, 2013 USD ($) $ / shares shares	Sep. 30, 2015 USD ($) $ / shares shares	Feb. 28, 2015 USD ($) $ / shares shares	Dec. 31, 2014 USD ($) shares	May. 31, 2015 USD ($) $ / shares shares	Sep. 30, 2015 USD ($) $ / shares shares	Sep. 30, 2014 USD ($)	Sep. 30, 2015 USD ($) $ / shares shares	Sep. 30, 2014 USD ($)	Dec. 31, 2013 USD ($) $ / shares
Schedule Of Capitalization Equity [Line Items]
Stock issued (in Shares) | shares			1,357,955
Exercise price of warrants issued (in Dollars per Unit) | $ / shares	115.40	9.52				9.52		9.52		16.45
Preferred stock, shares outstanding (in Shares) | shares		255,732		255,732		255,732		255,732
Shares issued below initial warrant exercise price of $115.40 per share (in Shares) | shares				536,091
2% Convertible Notes debt extinguished through common share issuance				$ 21,000,000
Common shares issued in public offering (in Shares) | shares		848,961	1,357,955		2,460,045
Common stock, issuance price per share (in Dollars per Share) | $ / shares		$ 2.79	$ 22.40		$ 6.87	$ 2.79		$ 2.79
Proceeds from issuance of common stock, net of transaction costs		$ 2,300,000	$ 29,400,000		$ 16,400,000			$ 48,049,115
Internal rate of return required to avoid additional cash payment on change of control (in Percent)		25.00%				25.00%		25.00%
Additional cash payment that could be required on change of control to achieve 25% internal rate of return on White Deer Securities Purchase Agreement		$ 0				$ 0		$ 0
Payments of stock issuance costs	$ 2,816,006
Warrant liability recognized	$ 8,626,000
Issuance discount outstanding		$ 0				$ 0		0
Share-Based Compensation Expense								$ 2,710,683	$ 9,497,044
Nonvested Restricted Stock Units [Member]
Schedule Of Capitalization Equity [Line Items]
Stock-based compensation, equity incentive plan, unvested shares (in Shares) | shares		72,092				72,092		72,092
Unrecognized share-based compensation cost		$ 975,865				$ 975,865		$ 975,865
Period for recognition of unrecognized compensation costs related to nonvested share based compensation (Duration)								8 months 12 days
Restricted Stock and Restricted Stock Units [Member]
Schedule Of Capitalization Equity [Line Items]
Share-Based Compensation Expense						$ 438,346	$ 2,480,352	$ 2,444,623	8,686,625
Stock-based compensation, equity incentive plan, unvested shares (in Shares) | shares		72,092		29,231		72,092		72,092
Share-based compensation capitalized						$ 83,425	437,612	$ 601,605	1,425,364
Series A Preferred Stock [Member]
Schedule Of Capitalization Equity [Line Items]
Stock issued (in Shares) | shares	500,000
Payment for redemption of stock										$ 50,000,000
Preferred stock, redemption premium										$ 6,250,000
Preferred stock, shares outstanding (in Shares) | shares		0				0		0
Dividends paid						$ 0	$ 0	$ 0	$ 0
Fair value recognized from public offering, net of offering costs	$ 38,552,994
Series B Preferred Stock [Member]
Schedule Of Capitalization Equity [Line Items]
Stock issued (in Shares) | shares	255,732
Number of votes per share of preferred stock (in Integer) | $ / shares		1				1		1
Dividend rights (in Dollars per Share) | $ / shares								$ 0.00
Liquidation preference (in Dollars per Share) | $ / shares		$ .001				$ .001		.001
Redemption price (in Dollars per Share) | $ / shares		$ .001				$ .001		$ .001
Share of common stock issuable under warrant issued as part of unit with each share of preferred stock (in Shares) | shares		1				1		1
Fair value recognized from public offering, net of offering costs	$ 5,000
Warrant [Member]
Schedule Of Capitalization Equity [Line Items]
Warrants to purchase common stock issued (in Shares) | shares	255,732
Series A Preferred Series B Preferred and Warrants to Purchase Common Stock [Member]
Schedule Of Capitalization Equity [Line Items]
Proceeds from stock issued	$ 50,000,000

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DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT (Schedule of Reconciliation of the Changes in Fair Value of Commodity Derivatives) (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Derivative Instruments and Price Risk Management [Abstract]
Beginning fair value of commodity derivatives	$ (3,633,216)	$ (5,852,801)	$ 5,044,125	$ (853,005)
Total gains (losses) on commodity derivatives	12,699,147	11,184,716	8,148,386	3,722,780
Cash settlements paid on commodity derivatives	(1,354,804)	313,451	(5,481,384)	2,775,591
Ending fair value of commodity derivatives	$ 7,711,127	$ 5,645,366	$ 7,711,127	$ 5,645,366

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BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES (Policies)

9 Months Ended

Sep. 30, 2015

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 $0 and $4 million at September 30, 2015 and December 31, 2014, respectively.  At December 31, 2014, the balance related to a drilling commitment agreement entered into pursuant to oil and natural gas leases. The commitment was fulfilled and funds released during the three months ended September 30, 2015.

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 nine months ended September 30, 2015 and 2014.

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 September 30, 2015 and 2014, the Company capitalized $814,011 and $1,354,556, respectively, of internal salaries, which included $78,390 and $624,629, respectively, of stock-based compensation. For the nine months ended September 30, 2015 and 2014, the Company capitalized $3,245,667 and $4,278,105, respectively, of internal salaries, which included $708,600, and $2,020,992, 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 nine months ended September 30, 2015 and 2014.

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 nine months ended September 30, 2015 and 2014. 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 nine months ended September 30, 2015 and the year ended December 31, 2014, the Company included $15,231,547 and $2,979,258, 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. Any required write-downs are included in the consolidated statement of operations as an impairment charge. Based on calculated reserves at September 30, 2015, the unamortized costs of the Company’s oil and natural gas properties exceeded the ceiling test limit by $158,278,000. As a result, the Company was required to record impairments of the net capitalized costs of its oil and natural gas properties in the amount of $158,278,000 and $304,903,000 for the three and nine months ended September 30, 2015, respectively. As of September 30, 2014, the unamortized costs of the Company’s oil and natural gas properties did not exceed the ceiling test limit and no impairment expense was recognized for the three and nine months ended September 30, 2014.

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 it can be reasonably estimated 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 September 30, 2015 and December 31, 2014, 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 of peer company data fairly represents the expected volatility it would experience if it were in the oil and natural gas industry over the expected term of the options. The Company used the simplified method to determine the expected term of the options due to the lack of historical data. Changes in these assumptions can materially affect the fair value estimate.

On May 27, 2011, the stockholders of the Company approved the 2011 Equity Incentive Plan (the “2011 Plan”), under which 35,714 shares of common stock were reserved. On October 22, 2012, 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 175,000 shares. On July 10, 2013, the stockholders of the Company approved an amendment to the 2011 Plan to increase the number of shares authorized for issuance under the 2011 Plan to 490,000 shares. On May 20, 2015, the stockholders of the Company approved an amendment to the 2011 Plan to increase the number of shares authorized for issuance under the 2011 Plan to 990,000 shares. The purpose of the 2011 Plan is to promote the success of the Company and its affiliates by facilitating the employment and retention of competent personnel and by furnishing incentives to those officers, directors and employees upon whose efforts the success of the Company and its affiliates will depend to a large degree. It is the intention of the Company to carry out the 2011 Plan through the granting of incentive stock options, nonqualified stock options, restricted stock awards, restricted stock unit awards, performance awards and stock appreciation rights. As of September 30, 2015, 42,491 stock options and 380,396 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 72,092 nonvested restricted stock units. As of September 30, 2015, there were 567,113 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 condensed 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 shares of common stock outstanding during the period. Diluted earnings per share are computed using the weighted average number of shares of common stock 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 nine months ended September 30, 2015 and 2014, the potentially dilutive shares were anti-dilutive and were thus not included in the net loss per share calculation.

As of September 30, 2015, (i) 72,092 nonvested restricted stock units were issued and outstanding and represent potentially dilutive shares; (ii) 30,759 stock options were issued and presently exercisable and represent potentially dilutive shares; (iii) 9,777 stock options were granted but were not presently exercisable and represent potentially dilutive shares; (iv) 255,732 warrants were issued and presently exercisable, which have an exercise price of $9.52 and represent potentially dilutive shares; (v) 11,165 warrants were issued and presently exercisable, which have an exercise price of $137.20 and represent potentially dilutive shares; (vi) 44,643 warrants were issued and presently exercisable, which have an exercise price of $994.00 and represent potentially dilutive shares; and (vii) $151.5 million of Convertible Notes were convertible into approximately 863,248 shares of common stock as of September 30, 2015 and represent 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’ creditworthiness, the Company’s creditworthiness, 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 marketplace participant’s view. Management believes that this approach provides a reasonable, non-biased, verifiable, and consistent methodology for valuing commodity derivative instruments (see Note 13 – Derivative Instruments and Price Risk Management).

Warrant Liability

From time to time, the Company may have financial instruments such as warrants that may be classified as liabilities when either (a) the holders possess rights to net cash settlement, (b) physical or net equity settlement is not in the Company’s control, or (c) the instruments contain other provisions that cause 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 6 – Preferred and Common Stock), the Company issued warrants that contain a put and other liability type provisions. Accordingly, these warrants are accounted for as a liability. This warrant liability is accounted for at fair value with changes in fair value reported in the consolidated statement 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, valuation of asset retirement obligations 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.

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FAIR VALUE (Tables)

9 Months Ended

Sep. 30, 2015

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 September 30, 2015:

	Fair Value Measurements at September 30, 2015 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	$	—	$	—		$	(187,000	)
Commodity Derivatives – Current Asset (oil puts)		—		14,310,070			—
Commodity Derivatives – Non Current Asset (oil puts)		—		3,442,664			—
Commodity Derivatives – Current Liability (oil put premiums)		—		(7,974,013	)		—
Commodity Derivatives – Long Term Liability (oil put premiums)		—		(2,067,594	)		—
Total	$	—	$	7,711,127		$	(187,000	)

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, 2014:

	Fair Value Measurements at December 31, 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 Asset (Liability)	$	—	$	—	$	(2,199,000	)
Commodity Derivatives – Current Asset (oil swaps)		—		5,044,125		—
Total	$	—	$	5,044,125	$	(2,199,000	)

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

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

Balance, at January 1, 2014	$	(15,703,000	)
Change in Fair Value of Warrant Liability		13,504,000
Balance, at December 31, 2014		(2,199,000	)
Change in Fair Value of Warrant Liability		2,012,000
Balance, at September 30, 2015	$	(187,000	)

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DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT (Narrative) (Details)	Sep. 30, 2015 USD ($) $ / shares	Jan. 05, 2015 USD ($) $ / shares	Feb. 19, 2013 USD ($) $ / shares	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)
Derivative Instruments and Price Risk Management [Abstract]
Barrels of outstanding NYMEX West Texas intermediate oil derivative swap contracts, oil settled (in Barrels)		120,000
Proceeds from settlement of oil derivative swap contracts | $		$ 5,317,300
Warrant liability recognized | $			$ 8,626,000
Warrants issued, price per warrant (in Dollars per Unit)			33.80
Expected volatility rate (in Percent)	80.00%		40.00%
Risk-free interest rate (in Percent)	1.65%		1.38%
Expected term (in Duration)	1067 days		1798 days
Exercise price of warrants (in Dollars per Unit)	$ 9.52
Fair value of warrants | $	$ 187,000			$ 2,199,000	$ 15,703,000
Average stock price valuation assumption (in Dollars per Share)	$ 2.34

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REVOLVING CREDIT FACILITY (Narrative) (Details)	9 Months Ended
	Sep. 30, 2015 USD ($)	Nov. 06, 2015 USD ($)	Oct. 06, 2015 USD ($)	Apr. 30, 2015 USD ($)	Dec. 31, 2014 USD ($)
Line Of Credit Facility [Line Items]
Credit facility amount outstanding	$ 159,683,000
Line of credit facility, excess of amount outstanding over borrowing base		$ 19,600,000
Prior to Scheduled Semi-Annual Lender Redetermination [Member]
Line Of Credit Facility [Line Items]
Current borrowing base under credit facility				$ 250,000,000
Subsequent to Scheduled Semi-Annual Lender Redetermination [Member]
Line Of Credit Facility [Line Items]
Current borrowing base under credit facility				$ 200,000,000
Wells Fargo Credit Agreement [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
Maturity date of credit facility (in Date)	Sep. 30, 2018
Effective interest rate at period end	2.70%
Facility covenant, minimum current ratio (in Ratio)	1.00
Facility covenant, maximum debt to EBITDA, current and through June 30, 2016 (in percent)	5.00
Facility covenant, maximum debt to EBITDA, July 01, 2016 - December 31, 2016 (in percent)	5.50
Facility covenant, maximum Senior Secured Debt to EBITDA (in percent)	2.50
Wells Fargo Credit Agreement [Member] | Minimum [Member]
Line Of Credit Facility [Line Items]
Commitment fee percentage (in Percent)	0.375%
Wells Fargo Credit Agreement [Member] | Minimum [Member] | Alternate Base rate Under Credit Facility [Member]
Line Of Credit Facility [Line Items]
Interest rate spread (in Percent)	0.75%
Wells Fargo Credit Agreement [Member] | Minimum [Member] | LIBOR Rate [Member]
Line Of Credit Facility [Line Items]
Interest rate spread (in Percent)	1.75%
Wells Fargo Credit Agreement [Member] | Maximum [Member]
Line Of Credit Facility [Line Items]
Commitment fee percentage (in Percent)	0.50%
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%
Percentage of projected production through next fiscal year end covered by hedges (in Percent)	70.00%
Wells Fargo Credit Agreement [Member] | Maximum [Member] | Alternate Base rate Under Credit Facility [Member]
Line Of Credit Facility [Line Items]
Interest rate spread (in Percent)	1.75%
Wells Fargo Credit Agreement [Member] | Maximum [Member] | LIBOR Rate [Member]
Line Of Credit Facility [Line Items]
Interest rate spread (in Percent)	2.75%
Wells Fargo Credit Agreement [Member] | Subsequent to Scheduled Semi-Annual Lender Redetermination [Member]
Line Of Credit Facility [Line Items]
Line of credit facility, excess of amount outstanding over borrowing base			$ 19,600,000
Wells Fargo Credit Agreement Letters of Credit [Member]
Line Of Credit Facility [Line Items]
Maximum amount available under credit facility	$ 5,000,000
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%
Wells Fargo Credit Agreement Letters of Credit [Member] | Minimum [Member]
Line Of Credit Facility [Line Items]
Interest on letters of credit (in Percent)	1.75%
Wells Fargo Credit Agreement Letters of Credit [Member] | Maximum [Member]
Line Of Credit Facility [Line Items]
Interest on letters of credit (in Percent)	2.75%

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) - USD ($)	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss	$ (330,044,369)	$ 10,057,937
Adjustments to Reconcile Net Loss to Net Cash Provided By Operating Activities:
Depletion of Oil and Natural Gas Properties	31,622,386	$ 24,071,676
Impairment of Oil and Natural Gas Properties	304,903,000
Depreciation and Amortization	559,138	$ 251,722
Amortization of Debt Issuance Costs	2,145,832	727,997
Accretion of Discount on Asset Retirement Obligations	153,007	63,837
Net Gains on Commodity Derivatives	(8,148,386)	(3,722,780)
Net Cash Settlements Received (Paid) on Commodity Derivatives	5,481,384	(2,775,591)
Warrant Revaluation (Gain) Expense	(2,012,000)	1,751,000
Share-Based Compensation Expense	2,710,683	9,497,044
Changes in Assets and Liabilities:
Decrease (Increase) in Trade Receivables - Oil and Natural Gas Revenues	3,200,513	(1,390,582)
Decrease (Increase) in Accounts Receivable - Joint Interest Partners	23,471,952	(1,224,056)
Decrease (Increase) in Other Receivables	119,337	(1,132,418)
Increase in Prepaid Expenses and Other Current Assets	(392,520)	(223,875)
(Increase) Decrease in Other Non-Current Assets	(35,882)	67,463
(Decrease) Increase in Accounts Payable	6,585,509	2,364,168
Decrease in Accrued Expenses	$ (4,867,351)	(7,813,470)
Increase in Other Non-Current Liabilities		198,551
(Decrease) Increase in Advances from Joint Interest Partners	$ (1,775,128)	200,434
Net Cash Provided By Operating Activities	33,677,105	30,969,057
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of Other Property and Equipment	(1,683,390)	(1,015,677)
Restricted Cash Released	$ 4,000,000	11,000,512
Payments of Restricted Cash		(2,648,721)
Decrease (Increase) in Deposits for Acquisitions	$ 140,173	(648,441)
Proceeds from Sale of Oil and Natural Gas Properties, Net of Transaction Costs		36,155,859
Investment in Oil and Natural Gas Properties	$ (175,371,888)	(391,368,324)
Net Cash Used For Investing Activities	$ (172,915,105)	(348,524,792)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Issuance of Convertible Senior Notes, Net of Transaction Costs		$ 166,893,211
Proceeds from Issuance of Common Stock, Net of Transaction Costs	$ 48,049,115
Advances on Revolving Credit Facility	100,000,000	$ 55,000,000
Payments on Revolving Credit Facility	(15,317,000)	(35,000,000)
Cash Paid for Finance Costs	(265,144)	(24,605)
Cash Paid for Debt Issuance Costs	$ (549,881)	(1,117,871)
Proceeds from Exercise of Stock Options and Warrants		110,750
Net Cash Provided by Financing Activities	$ 131,917,090	185,861,485
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(7,320,910)	(131,694,250)
CASH AND CASH EQUIVALENTS - BEGINNING OF PERIOD	12,389,230	144,255,438
CASH AND CASH EQUIVALENTS - END OF PERIOD	5,068,320	12,561,188
Supplemental Disclosure of Cash Flow Information
Cash Paid During the Period for Interest	$ 4,124,010	$ 1,867,433
Cash Paid During the Period for Income Taxes
Non-Cash Financing and Investing Activities:
Oil and Natural Gas Properties Included in Account Payable	$ 19,997,664	$ 92,963,874
Stock-Based Compensation Capitalized to Oil and Natural Gas Properties	708,600	2,020,992
Asset Retirement Obligation Costs and Liabilities	$ 440,536	$ 1,669,757

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RELATED PARTY TRANSACTIONS

9 Months Ended

Sep. 30, 2015

Related Party Transactions [Abstract]

RELATED PARTY TRANSACTIONS

NOTE 5  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”), 255,732 shares of Series B Voting Preferred Stock (“Series B Preferred Stock”) and warrants to purchase an initial aggregate amount of 255,732 shares of the Company’s common stock at an initial exercise price of $115.40 per share, for an aggregate $50 million. Pursuant to the Securities 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 during 2013, 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. On January 28, 2015, Mr. Edelman resigned from his position as a director of the Company and Ben Guill, a Managing Partner of White Deer Energy, was appointed to the Board of Directors. For additional information regarding the Securities Purchase Agreement with White Deer Energy, see Note 6 — 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 255,732 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 139,280 shares of Company common stock and 254,643 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 393,923 shares of common stock and 255,732 shares of common stock underlying the warrants held by White Deer Energy, and the SEC declared the registration statement effective on May 30, 2014. In February 2015, the Company completed a public offering of 1,357,955 shares of common stock at a price of $22.40 per share for total net proceeds of approximately $29.4 million. White Deer Energy purchased 669,643 common shares in the public offering. White Deer Energy’s participation in the public offering was approved by the Company’s board of directors.

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DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT (Tables)

9 Months Ended

Sep. 30, 2015

Derivative Instruments and Price Risk Management [Abstract]

Schedule of Open Commodity Contracts

On January 5, 2015, the Company settled its outstanding NYMEX West Texas Intermediate oil derivative swap contracts on a total of 120,000 barrels of oil, resulting in the receipt of $5,317,300 in cash. On April 7, 2015, the Company entered into put option contracts for oil volumes produced in May 2015 through December 2016, whereby premiums are paid monthly throughout the life of the contracts. Open contracts as of September 30, 2015 are provided in the table below.

Settlement Period	Daily Volume Oil (Bbls)		Put Option Fixed Price Per Bbl		Total Volume (Bbls)		Premium Paid Per Bbl		Total Premiums Due
October 2015 – December 2015		4,000	$	55.00		368,000	$	4.88	$	1,795,840
January 2016 – December 2016		3,000	$	60.00		1,098,000	$	7.54	$	8,278,920

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 nine months ended September 30, 2015 and 2014.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Beginning fair value of commodity derivatives	$	(3,633,216	)	$	(5,852,801	)	$	5,044,125		$	(853,005	)
Total gains on commodity derivatives		12,699,147			11,184,716			8,148,386			3,722,780
Cash settlements (received) paid on commodity derivatives		(1,354,804	)		313,451			(5,481,384	)		2,775,591
Ending fair value of commodity derivatives	$	7,711,127		$	5,645,366		$	7,711,127		$	5,645,366

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STOCK OPTIONS AND WARRANTS (Schedule of Stock Options Outstanding Roll Forward) (Details)	9 Months Ended
	Sep. 30, 2015 $ / shares shares
Stock Options and Warrants [Abstract]
Stock options outstanding at beginning of period (in Shares) | shares	59,746
Stock options granted (in Shares) | shares
Stock options canceled (in Shares) | shares	(19,210)
Stock options exercised (in Shares) | shares
Stock options outstanding at end of period (in Shares) | shares	40,536
Stock options exercisable at end of period (in Shares) | shares	30,759
Stock options outstanding weighted average exercise price at beginning of period (in Dollars per Share)	$ 171.20
Stock options granted weighted average exercise price (in Dollars per Share)
Stock options canceled weighted average exercise price (in Dollars per Share)	$ 218.39
Stock options exercised weighted average exercise price (in Dollars per Share)
Stock options outstanding weighted average exercise price at end of period (in Dollars per Share)	$ 148.78
Stock options exercisable, weighted average exercise price at end of period (in Dollars per Share)	$ 150.83

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SUBSEQUENT EVENTS

9 Months Ended

Sep. 30, 2015

Subsequent Events [Abstract]

SUBSEQUENT EVENTS

NOTE 15 SUBSEQUENT EVENTS

Joint Venture Agreement

On October 1, 2015, the Company closed the purchase and sale agreement with Koch Exploration. Subject to customary closing conditions, Koch Exploration acquired a 30% working interest in approximately 25,000 undeveloped net acres held by the Company in McKenzie County, North Dakota and approximately 4,400 undeveloped net acres held by the Company in Richland County, Montana for approximately $17.4 million. Koch Exploration reimbursed the Company approximately $5.4 million for its proportionate share of recently drilled and uncompleted wells in southern McKenzie County, North Dakota. Total proceeds to the Company upon closing the transaction were approximately $22.8 million and all proceeds were used to repay outstanding borrowings on the Credit Facility, reducing the outstanding balance from $160 million to $139.6 million subsequent to September 30, 2015.

Borrowing Base Redetermination

On October 6, 2015 the Company’s borrowing base under the Credit Facility was decreased from $200 million to $120 million as part of the Company’s regularly scheduled semi-annual redetermination by its lenders. The decrease in the borrowing base resulted in the outstanding balance of the Credit Facility to exceed the revised borrowing base by approximately $19.6 million as of November 6, 2015 (See Note 8 – Revolving Credit Facility).

Forbearance Agreement

On November 5, 2015, the Company, along with certain of its subsidiaries (the “Guarantors”), entered into a forbearance agreement (the “Forbearance Agreement”) with the lenders (the “Lenders”) party to the Credit Agreement, and Wells Fargo Bank, N.A., as agent for the Lenders (the “Agent”). Pursuant to the Forbearance Agreement, the Lenders and the Agent agreed to forbear from exercising their rights and remedies under the Credit Agreement until December 18, 2015 (the “Forbearance Period”) with respect to certain events of defaults under the Credit Agreement (the “Specified Defaults”).

The Forbearance Period will terminate immediately upon the occurrence of any of the following: (i) a default under the Credit Agreement other than the Specified Defaults; (ii) any misrepresentation by the Company or any of the Guarantors under the Forbearance Agreement; (iii) the failure of the Company or any of the Guarantors to perform, observe or comply with the terms of the Forbearance Agreement; (iv) the commencement of any bankruptcy, insolvency or similar proceeding against the Company or any of the Guarantors or the appointment of a trustee or similar official for the Company or any of the Guarantors or a substantial part of its property; (v) any default in excess of $5,000,000 under certain specified material contracts; or (vi) any event during the Forbearance Period which has a Material Adverse Effect (as defined in the Credit Agreement).

In exchange for the Lenders and the Agent agreeing to forbear their rights and remedies under the Credit Agreement, the Company has agreed during the Forbearance Period to, among other things: (i) make monthly interest payments at the Alternate Base Rate (as defined in the Credit Agreement) plus 1.75%; (ii) pay the Lenders a fee equal to 0.50% of the outstanding principal balance of the loans under the Credit Agreement; (iii) use 100% of the Net Cash Proceeds (as defined in the Credit Agreement) received by the Company or any Guarantor to make mandatory prepayments of the loans under the Credit Agreement in certain circumstances; (iv) periodically deliver to the Agent and the Lenders certain financial and budget information; (v) cause unrestricted cash and cash equivalents to not be less than $1,000,000 at the end of each week; and (vi) limit capital expenditures to $300,000.

The foregoing description of the Forbearance Agreement is a summary only and is qualified in its entirety by reference to the Forbearance Agreement, a copy of which is attached as Exhibit 10.3 to this Quarterly Report on Form 10-Q and incorporated herein by reference.

Debt Conversion

On October 22, 2015, the Company entered into an agreement with a holder of the Convertible Notes pursuant to which the Company and the noteholder agreed to exchange approximately $3 million principal value of Convertible Notes for a number of shares of common stock to be issued based upon a formula that utilizes a 15% discount to the volume weighted average price of the Company’s common stock over a period of 15 consecutive trading days starting October 23, 2015 and ending on approximately November 12, 2015, which is expected to be approximately 880,000 shares of common stock based on an average estimated price of approximately $1.70 per common share. As a result, the Company expects to recognize approximately $1.5 million of debt conversion expense for the fair value of the shares of common stock issued in excess of the shares of common stock underlying the original convertible note indenture agreement. Following the completion of the exchange, approximately $148.5 million aggregate principal amount of the Convertible Notes will remain outstanding.