Edgar Filing: Emerald Oil, Inc.

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2015

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). Yesx No ¨

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

Large accelerated filer ¨		Accelerated filer x

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

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

As of August 4, 2015, there were 7,856,325 shares of Common Stock, $0.001 par value per share, outstanding.

EMERALD OIL, INC.

INDEX

			Page of
			Form 10-Q

PART I.	FINANCIAL INFORMATION		1

	ITEM 1.	FINANCIAL STATEMENTS (UNAUDITED)	1

		Condensed Consolidated Balance Sheets as of June 30, 2015 and December 31, 2014	1

		Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2015 and 2014	2

		Condensed Consolidated Statements of Cash Flows for the six months ended June 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	21

	ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	37

	ITEM 4.	CONTROLS AND PROCEDURES	38

PART II.	OTHER INFORMATION		39

	ITEM 1.	LEGAL PROCEEDINGS	39

	ITEM 1A.	RISK FACTORS	39

	ITEM 6.	EXHIBITS	42

SIGNATURES			44

PART 1 — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

EMERALD OIL, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	June 30, 2015			December 31, 2014
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	19,116,956		$	12,389,230
Restricted Cash		2,000,000			—
Accounts Receivable – Oil and Natural Gas Sales		9,107,331			7,203,455
Accounts Receivable – Joint Interest Partners		14,296,377			31,842,464
Other Receivables		304,624			980,317
Prepaid Expenses and Other Current Assets		776,292			289,061
Fair Value of Commodity Derivatives		—			5,044,125
Total Current Assets		45,601,580			57,748,652
PROPERTY AND EQUIPMENT
Oil and Natural Gas Properties, Full Cost Method, at cost:
Proved Oil and Natural Gas Properties		678,944,015			593,472,170
Unproved Oil and Natural Gas Properties		149,994,517			166,708,263
Equipment and Facilities		17,223,706			6,086,896
Other Property and Equipment		4,644,900			2,583,372
Total Property and Equipment		850,807,138			768,850,701
Less – Accumulated Depreciation, Depletion and Amortization		(317,035,267	)		(149,703,417	)
Total Property and Equipment, Net		533,771,871			619,147,284
Restricted Cash		—			4,000,000
Debt Issuance Costs, Net of Amortization		5,433,819			5,779,125
Deposits on Acquisitions		—			140,173
Deferred Tax Assets, Net		1,813,561			1,813,796
Other Non-Current Assets		426,873			430,846
Total Assets	$	587,047,704		$	689,059,876
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts Payable	$	59,492,828		$	120,136,903
Revolving Credit Facility		159,683,000			—
Convertible Senior Notes		151,500,000			—
Fair Value of Commodity Derivatives		3,167,271			—
Accrued Expenses		4,546,468			11,267,831
Advances from Joint Interest Partners		2,020,760			2,577,247
Deferred Tax Liability, Net		1,813,561			1,813,796
Total Current Liabilities		382,223,888			135,795,777
LONG-TERM LIABILITIES
Revolving Credit Facility		—			75,000,000
Convertible Senior Notes		—			151,500,000
Asset Retirement Obligations		3,141,859			2,671,975
Warrant Liability		408,000			2,199,000
Fair Value of Commodity Derivatives		465,945			—
Total Liabilities		386,239,692			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 June 30, 2015 and December 31, 2014. Liquidation preference value of $256 as of June 30, 2015 and December 31, 2014.		256			256

STOCKHOLDERS’ EQUITY
Common Stock, Par Value $.001; 500,000,000 Shares Authorized, 7,856,325 and 3,891,431 Shares Issued and Outstanding, respectively		7,856			3,891
Additional Paid-In Capital		504,815,447			455,087,277
Accumulated Deficit		(304,015,547	)		(133,198,300	)
Total Stockholders’ Equity		200,807,756			321,892,868
Total Liabilities and Stockholders’ Equity	$	587,047,704		$	689,059,876

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

EMERALD OIL, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
REVENUES
Oil Sales	$	21,575,315		$	30,288,128		$	35,631,347		$	48,722,936
Natural Gas Sales		264,691			966,280			729,863			1,600,344
Net Losses on Commodity Derivatives		(4,823,936	)		(6,663,083	)		(4,550,761	)		(7,461,936	)
Total Revenues		17,016,070			24,591,325			31,810,449			42,861,344
OPERATING EXPENSES
Production Expenses		10,048,350			3,897,482			17,770,504			6,514,726
Production Taxes		2,251,080			3,400,874			3,834,375			5,489,610
General and Administrative Expenses		3,878,473			7,633,559			8,673,998			16,125,563
Depletion of Oil and Natural Gas Properties		10,034,956			8,600,878			20,380,062			14,878,110
Impairment of Oil and Natural Gas Properties		61,361,000			—			146,625,000			—
Depreciation and Amortization		167,634			81,497			326,789			147,257
Accretion of Discount on Asset Retirement Obligations		50,928			20,080			100,507			35,800
Standby Rig Expense		826,061			—			2,372,665			—
Total Operating Expenses		88,618,482			23,634,370			200,083,900			43,191,066
INCOME (LOSS) FROM OPERATIONS		(71,602,412	)		956,955			(168,273,451	)		(329,722	)

OTHER INCOME (EXPENSE)
Interest Expense		(2,616,000	)		(1,136,377	)		(4,309,552	)		(1,308,463	)
Warrant Revaluation Gain (Expense)		1,089,000			(1,771,000	)		1,791,000			(1,967,000	)
Other Income		—			371			257			4,047
Total Other Expense, Net		(1,527,000	)		(2,907,006	)		(2,518,295	)		(3,271,416	)

LOSS BEFORE INCOME TAXES		(73,129,412	)		(1,950,051	)		(170,791,746	)		(3,601,138	)

INCOME TAX PROVISION		—			—			—			—

NET LOSS	$	(73,129,412	)	$	(1,950,051	)	$	(170,791,746	)	$	(3,601,138	)

Net Loss Per Common Share – Basic and Diluted	$	(11.70	)	$	(0.59	)	$	(31.18	)	$	(1.09	)

Weighted Average Shares Outstanding – Basic and Diluted		6,248,310			3,316,161			5,476,843			3,312,582

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

EMERALD OIL, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Six Months Ended June 30,
	2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss	$	(170,791,746	)	$	(3,601,138	)
Adjustments to Reconcile Net Loss to Net Cash Provided By Operating Activities:
Depletion of Oil and Natural Gas Properties		20,380,062			14,878,110
Impairment of Oil and Natural Gas Properties		146,625,000			—
Depreciation and Amortization		326,788			147,257
Amortization of Debt Issuance Costs		1,045,217			377,463
Accretion of Discount on Asset Retirement Obligations		100,507			35,800
Net Losses on Commodity Derivatives		4,550,761			7,461,936
Net Cash Settlements Received (Paid) on Commodity Derivatives		4,126,580			(2,462,140	)
Warrant Revaluation (Gain) Expense		(1,791,000	)		1,967,000
Share-Based Compensation Expense		2,163,753			6,678,883
Changes in Assets and Liabilities:
Increase in Trade Receivables – Oil and Natural Gas Revenues		(1,903,876	)		(636,959	)
Decrease (Increase) in Accounts Receivable – Joint Interest Partners		17,546,087			(4,873,541	)
Decrease (Increase) in Other Receivables		675,693			(1,022,732	)
Increase in Prepaid Expenses and Other Current Assets		(487,231	)		(328,131	)
Decrease in Other Non-Current Assets		3,972			130,437
(Decrease) Increase in Accounts Payable		(2,963,252	)		1,888,872
Decrease in Accrued Expenses		(5,462,417	)		(2,474,083	)
Increase in Other Non-Current Liabilities		—			209,333
(Decrease) Increase in Advances from Joint Interest Partners		(556,487	)		1,518,372
Net Cash Provided By Operating Activities		13,588,411			19,894,739
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of Other Property and Equipment		(2,061,528	)		(754,492	)
Restricted Cash Released		2,000,000			11,000,512
Payments of Restricted Cash		—			(2,648,721	)
Increase (Decrease) in Deposits for Acquisitions		140,173			(178,967	)
Proceeds from Sale of Oil and Natural Gas Properties, Net of Transaction Costs		—			238,069
Investment in Oil and Natural Gas Properties		(136,601,645	)		(204,113,902	)
Net Cash Used For Investing Activities		(136,523,000	)		(196,457,501	)
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		45,753,027			—
Advances on Revolving Credit Facility		100,000,000			35,000,000
Payments on Revolving Credit Facility		(15,317,000	)		(35,000,000	)
Cash Paid for Finance Costs		(73,801	)		(24,605	)
Cash Paid for Debt Issuance Costs		(699,911	)		(500,365	)
Proceeds from Exercise of Stock Options and Warrants		—			110,750
Net Cash Provided by Financing Activities		129,662,315			166,478,991
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		6,727,726			(10,083,771	)
CASH AND CASH EQUIVALENTS – BEGINNING OF PERIOD		12,389,230			144,255,438
CASH AND CASH EQUIVALENTS – END OF PERIOD	$	19,116,956		$	134,171,667
Supplemental Disclosure of Cash Flow Information
Cash Paid During the Period for Interest	$	1,375,758		$	—
Cash Paid During the Period for Income Taxes	$	—		$	—
Non-Cash Financing and Investing Activities:
Oil and Natural Gas Properties Included in Accounts Payable	$	50,276,501		$	86,500,675
Stock-Based Compensation Capitalized to Oil and Natural Gas Properties	$	630,210		$	1,396,362
Asset Retirement Obligation Costs and Liabilities	$	369,377		$	515,199

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

EMERALD OIL, INC.

Notes to Condensed Consolidated Financial Statements

Unaudited

NOTE 1 ORGANIZATION AND NATURE OF BUSINESS

Description of Operations — Emerald Oil, Inc., a 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 June 30, 2015 and for the three and six months ended June 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 June 30, 2015 and for the three and six months ended June 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

The Company’s board of directors approved, subject to stockholder approval, 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). On May 20, 2015, a majority of the Company’s stockholders approved the reverse stock split. This reverse stock split decreased the issued and outstanding shares 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 underlying 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 stock, warrant and option transactions 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 $2 million and $4 million at June 30, 2015 and December 31, 2014, respectively. At June 30, 2015 and December 31, 2014, the balance related to a drilling commitment agreement entered into pursuant to oil and natural gas leases.

Accounts Receivable

The Company records estimated oil and natural gas revenue receivable from third parties at its net revenue interest. The Company also reflects costs incurred on behalf of joint interest partners in accounts receivable. Management periodically reviews accounts receivable amounts for collectability and records its allowance for uncollectible receivables under the specific identification method. The Company did not record any allowance for uncollectible receivables during the three and six months ended June 30, 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 June 30, 2015 and 2014, the Company capitalized $1,308,736 and $1,538,567, respectively, of internal salaries, which included $299,177, and $735,393, respectively, of stock-based compensation. For the six months ended June 30, 2015 and 2014, the Company capitalized $2,431,656 and $2,923,549, respectively, of internal salaries, which included $630,210, and $1,396,362, respectively, of stock-based compensation. Internal salaries are capitalized based on employee time allocated to the acquisition of leaseholds and development of oil and natural gas properties. The Company capitalized no interest in the three and six months ended June 30, 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 six months ended June 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 six months ended June 30, 2015 and the year ended December 31, 2014, the Company included $6,737,741 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 June 30, 2015, the unamortized costs of the Company’s oil and natural gas properties exceeded the ceiling test limit by $61,361,000. 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 $61,361,000 and $146,625,000 for the three and six months ended June 30, 2015, respectively. As of June 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 six months ended June 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 June 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 June 30, 2015, 52,244 stock options and 376,516 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 71,925 nonvested restricted stock units. As of June 30, 2015, there were 561,240 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 six months ended June 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 June 30, 2015, (i) 71,925 nonvested restricted stock units were issued and outstanding and represent potentially dilutive shares; (ii) 31,716 stock options were issued and presently exercisable and represent potentially dilutive shares; (iii) 18,573 stock options were granted but are not presently exercisable and represent potentially dilutive shares; (iv) 255,732 warrants were issued and presently exercisable, which have an exercise price of $16.45 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 senior notes were convertible into approximately 863,248 shares of common stock as of June 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.

NOTE 3 LIQUIDITY

The Company was not in compliance with the total debt to EBITDA and Senior Secured Debt-to-EBITDA ratios under its senior secured revolving credit facility (the “Credit Facility”) as of June 30, 2015. A resultant 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 balance of the Credit Facility and Convertible Notes as a current liability as of June 30, 2015. The Company has been in discussions with its lending group regarding amending its leverage ratio covenants during the upcoming scheduled borrowing base redetermination, which discussions began in July 2015. Based on those discussions, the Company and its lending group have agreed in principle to adjust the covenants to provide for more flexibility given lower forecasted adjusted EBITDA due to the lower commodity price environment. The Company’s borrowing base will be reduced as a result of this redetermination. The Company anticipates the execution of this amendment and redetermination in the third quarter of 2015; however, no assurances can be given that these transactions will be successfully completed. The Company’s inability to close the amendment to the Credit Facility would have an adverse effect on the Company’s operations and liquidity.

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 its revolving credit facility.

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 4,300 net acres located 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 six months ended June 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 June 30, 2014			Six Months Ended June 30, 2014
Revenues	$	28,849,510		$	50,864,472
Net Loss	$	(597,506	)	$	(731,176	)

Net Loss Per Share – Basic and Diluted	$	(0.18	)	$	(0.22	)

Weighted Average Shares Outstanding – Basic and Diluted		3,316,161			3,312,582

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.

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 principal of $50,000,000 and redemption premiums of $6,250,000, and no shares of Series A Preferred Stock remained outstanding as of June 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 six months ended June 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 2.0% Convertible Senior Notes (the “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 at an average price of $6.87 per share for total net proceeds of approximately $16.4 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 $41.06 to $16.45 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 necessary 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 June 30, 2015 or December 31, 2014.

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

	June 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		408,000		2,199,000		8,626,000
Total	$	408,256	$	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 at-the-market continuous offering program totaling 2,460,045 at an average price of $6.87 per share for total net proceeds of approximately $16.4 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 $426,396 and $2,746,344 for the three months ended June 30, 2015 and 2014, respectively, and $2,006,277 and $6,206,274 for the six months ended June 30, 2015 and 2014, respectively. As of June 30, 2015, there were 71,925 non-vested restricted stock units and $1,314,756 associated remaining unrecognized compensation expense, which is expected to be recognized over the weighted-average period of 0.90 years. The Company capitalized compensation expense associated with the restricted stock and restricted stock units of $219,726 and $548,036 to oil and natural gas properties for the three months ended June 30, 2015 and 2014, respectively, and $518,180 and $987,751 for the six months ended June 30, 2015 and 2014, respectively.

A summary of the restricted stock units and restricted stock shares activity during the six months ended June 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		51,550			15.70
Canceled		(3,461	)		16.40
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 June 30, 2015		71,925		$	58.31

NOTE 7 STOCK OPTIONS AND WARRANTS

Stock Options

The Company granted no stock options during the six months ended June 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 June 30, 2015 and 2014 was $103,778 and $237,236, respectively, net of $0 tax. The impact on the Company’s condensed consolidated statement of operations of stock-based compensation expense related to options granted for the six-month periods ended June 30, 2015 and 2014 was $157,476 and $472,609, respectively, net of $0 tax. The Company capitalized $79,452, and $187,357 in compensation to oil and natural gas properties related to outstanding options for the three months ended June 30, 2015 and 2014, respectively, and $112,030 and $408,611 for the six months ended June 30, 2015 and 2014, respectively. The Company had $386,766 of total unrecognized compensation cost related to nonvested stock options granted as of June 30, 2015. The remaining cost is expected to be recognized over a weighted-average period of 0.72 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 six months ended June 30, 2015 is as follows:

	Number of Options			Weighted Average Exercise Price
Balance outstanding at January 1, 2015		59,746		$	171.20

Granted		—			—
Canceled		(9,457	)		143.33
Exercised		—			—

Balance outstanding at June 30, 2015		50,289		$	176.37

Options exercisable at June 30, 2015		31,716		$	194.66

At June 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		18,407		3.64	$	142.44		8,926		3.55	$	145.02
2013		10,160		5.29		141.89		4,750		5.38		136.97
2012		15,626		1.96		163.05		11,944		1.93		164.98
Prior		6,096		0.73		370.46		6,096		0.73		370.46

Total		50,289		3.10	$	176.37		31,716		2.67	$	194.66

Warrants

The table below reflects the status of warrants outstanding at June 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	$	16.45	December 31, 2019
Total		311,540

No warrants expired or were forfeited during the six months ended June 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 June 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 (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 June 30, 2015, the Company had drawn approximately $160 million toward its $200 million borrowing base under the Credit Facility.

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 June 30, 2015, the annual interest rate on the Credit Facility was 2.82%.

A portion of the Credit Facility not in excess of $5 million will be available for the issuance of letters of credit by Wells Fargo. The Company will pay a rate per annum ranging from 1.75% to 2.75% on the face amount of each letter of credit issued and will pay a fronting fee equal to the greater of $500 and 0.125% of the face amount of each letter of credit issued. As of June 30, 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 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 June 30, 2015. The Company has been in discussions with its lending group regarding amending its leverage ratio covenants during the upcoming scheduled borrowing base redetermination, which discussions began in July 2015. Based on those discussions, the Company and its lending group have agreed in principle to adjust the covenants to provide for more flexibility given lower forecasted adjusted EBITDA due to the lower commodity price environment. The Company’s borrowing base will be reduced as a result of this redetermination. A resultant breach of the covenants under the Credit Facility could cause a default under the reserve based 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 due in 2019 and permit the holders of those notes to accelerate their maturity. The Company anticipates the execution of this redetermination in the third quarter of 2015. In accordance with the provisions under ASC 470-10-45-1, the Company has classified the balance of the Credit Facility as a current liability as of June 30, 2015. Upon closing the amendment to the Credit Facility in the third quarter of 2015, the Company expects to reclassify the Credit Facility to a long term liability. Please see Item 2. Recent Developments of this report for further information regarding changes to financing arrangements subsequent to June 30, 2015.

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.

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. 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 as of June 30, 2015. However, the Company does not believe further conversion will take place due to the term remaining on the Convertible Notes, and in the event of conversion, holders would forgo all future interest payments. As a result, the Convertible Notes have been classified as long-term debt as of June 30, 2015.

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

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

Holders may convert their Convertible Notes at their option at any time prior to the close of business on the business day immediately preceding the maturity date of the Convertible Notes. The conversion rate for the Convertible Notes is 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. If an Event of Default (as defined in the Indenture) occurs and is continuing, the Trustee or the holders of at least 25% in aggregate principal amount of the then-outstanding Convertible Notes may declare by written notice all the Convertible Notes to be immediately due and payable in full. The Company was in compliance with all covenants as of June 30, 2015. 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 June 30, 2015. Upon closing the amendment to the Credit Facility in the third quarter of 2015, the Company expects to reclassify the Convertible Notes to a long term liability.

In December 2014, the Company issued 536,091 shares of common stock to extinguish $21,000,000 of Convertible Notes. The Convertible Notes had 119,658 underlying shares of common stock under the terms of the original indenture agreement. 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 original convertible note indenture agreement.

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 six months ended June 30, 2015 and the year ended December 31, 2014:

	Six Months Ended June 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		369,377		1,817,939
Accretion of Discount on Asset Retirement Obligations		100,507		104,803
Wells Settled Through P&A		—		(72,555	)
Liabilities Associated with Properties Sold		—		(19,317	)
Ending Asset Retirement Obligation	$	3,141,859	$	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 June 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.

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 June 30, 2015:

	Fair Value Measurements at June 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	$	—	$	—		$	(408,000	)
Commodity Derivatives – Current Asset (oil puts)		—		4,522,832			—
Commodity Derivatives – Non Current Asset (oil puts)		—		3,662,096			—
Commodity Derivatives – Current Liability (oil put premiums)		—		(7,690,103	)		—
Commodity Derivatives – Long Term Liability (oil put premiums)		—		(4,128,041	)		—
Total	$	—	$	(3,633,216	)	$	(408,000	)

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		1,791,000
Balance, at June 30, 2015	$	(408,000	)

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 (expense) was $1,089,000 and $(1,771,000) for the three months ended June 30, 2015 and 2014, respectively, and $1,791,000 and $(1,967,000) for the six months ended June 30, 2015 and 2014, respectively. The warrant revaluation expense is included in Other Income/Expense on the accompanying Condensed Consolidated Statements of Operations. See discussion of assumptions used in valuing the warrants at Note 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 $75.8 million at June 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.

NOTE 13 DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT

Commodity

The Company utilizes oil swap contracts to (i) reduce the effects of volatility in price changes on the oil commodities it produces and sells, (ii) reduce commodity price risk and (iii) provide a base level of cash flow in order to assure it can execute at least a portion of its capital spending.

All derivative positions are carried at their fair value on the condensed consolidated balance sheet and are marked-to-market at the end of each period. The Company has a master netting agreement on each of the individual oil contracts. Therefore, 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 a cash settlement received of $5,317,300. 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 June 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
July 2015 – December 2015		4,000	$	55.00		736,000	$	4.88	$	3,591,680
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 six months ended June 30, 2015 and 2014.

	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
Beginning fair value of commodity derivatives	$	—		$	(1,098,474	)	$	5,044,125		$	(853,005	)
Total losses on commodity derivatives		(4,823,936	)		(6,663,083	)		(4,550,761	)		(7,461,936	)
Cash settlements paid (received) on commodity derivatives		1,190,720			1,908,756			(4,126,580	)		2,462,140
Ending fair value of commodity derivatives	$	(3,633,216	)	$	(5,852,801	)	$	(3,633,216	)	$	(5,852,801	)

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

The Company estimated the value of the warrants issued with the Securities Purchase Agreement on the date of issuance to be $8,626,000, or $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 June 30, 2015, using a Black-Scholes model with the following assumptions: a term of 1,130 trading days, exercise price of $16.45, a 15-day volume weighted average stock price of $4.88, volatility rate of 75%, and a risk-free interest rate of 1.65%. As of June 30, 2015, the fair value of the warrants was $408,000, 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.

NOTE 14 COMMITMENTS AND CONTINGENCIES

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.

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

NOTE 15 SUBSEQUENT EVENTS

Joint Venture Agreement

On July 31, 2015, the Company entered into a purchase and sale agreement with Koch Exploration (“Koch”), a wholly owned subsidiary of Koch Industries Inc. Subject to customary closing conditions, Koch will acquire a 30% working interest in approximately 25,000 undeveloped net acres held by the Company in McKenzie County, North Dakota for $16.6 million. Separately, Koch Exploration has agreed to acquire a portion of 4,500 undeveloped net acres held by the Company in Richland County, Montana for $0.9 million. Koch will also reimburse the Company $6.9 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 will be approximately $24.4 million.

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 Report on Form 10-Q for the quarter ended March 31, 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.

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 June 30, 2015, we had approximately 117,000 net acres in the Williston Basin. We operate approximately 98,000 net acres, or 84% of our total net acreage.

Our acreage holdings are comprised of the operating areas below:

71,000 net acres in the Low Rider area of McKenzie County, North Dakota;

7,000 net acres in the Richland area of Richland County, Montana;

6,000 net acres in the Pronghorn Sand formation in Stark and Billings Counties, North Dakota in the core of the Pronghorn field; and

33,000 net acres in the Lewis & Clark area of McKenzie County, North Dakota south of the Low Rider area.

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 $44.7 million in drilling and completion costs during the second quarter of 2015 and $51.8 million in total capital costs, which were primarily attributable to the completion of eight gross (7.2 net) wells and drilling two gross (2.0) net wells during the quarter. We have incurred $61.9 million of drilling and completion costs toward our total 2015 capital expenditure budget through the first half of 2015. We also incurred approximately $6.4 million during the quarter on the installation of new well connect infrastructure and gathering facilities to reduce the need for trucks and other field transportation costs.

We expect to fund our 2015 capital program through existing cash on hand, our expected cash flows from operations, and expected borrowing capacity under our revolving credit facility. Because we have a backlog of drilling permits, we may add additional wells to our 2015 development schedule if commodity prices improve. As of June 30, 2015, we had four wells that had been drilled and remain to be completed. We expect the wells to be completed by the end of the third quarter of 2015.

Recent Developments

Amendment to Our Credit Facility

On April 30, 2015, in connection with our semi-annual borrowing base redetermination we and our lending group entered into an amendment to our Credit Facility. The amendment to the Credit Facility changed the borrowing base amount from $250 million to $200 million. We were not in compliance with the total debt to EBITDA and Senior Secured Debt to EBITDA ratios under the Credit Facility as of June 30, 2015. We have been in discussions with our lending group regarding amending its leverage ratio covenants during the upcoming scheduled borrowing base redetermination, which discussions began in July 2015. Based on those discussions, we have agreed in principle to adjust the covenants to provide for more flexibility given lower forecasted adjusted EBITDA due to the lower commodity price environment. Our borrowing base will be reduced as a result of this redetermination. A resultant breach of the covenants under our Credit Facility could cause a default under the reserve based 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 due in 2019 and permit the holders of those notes to accelerate their maturity. We anticipate the completion of the redetermination in the third quarter of 2015.

Joint Venture Agreement

On July 31, 2015, we entered into a purchase and sale agreement with Koch Exploration (“Koch”), a wholly owned subsidiary of Koch Industries Inc. Subject to customary closing conditions, Koch will acquire a 30% working interest in approximately 25,000 undeveloped net acres held by Emerald in McKenzie County, North Dakota for $16.6 million. Separately, Koch Exploration has agreed to acquire a portion of 4,500 undeveloped net acres held by Emerald in Richland County, Montana for $0.9 million. Koch will also reimburse Emerald $6.6 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 will be approximately $24.4 million and all proceeds will be used to repay outstanding borrowings on the credit facility.

In conjunction with the transaction, Emerald and Koch Exploration have entered into a drilling agreement whereby the companies have agreed to drill two wells in 2016 in southern McKenzie County, ND 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 company in the future, the leasehold and costs will be split evenly between them.

Finance Update

During April and May 2015, we issued 2,460,045 shares of common stock through our at-the-market continuous offering program at an average price of $6.87 per share for total net proceeds of approximately $16.4 million. These sales were made pursuant to the terms of the equity distribution agreement dated April 2, 2015.

On June 11, 2015, we signed a term sheet with respect to a $75.0 million secured second lien term loan facility with a financial institution. This process is currently proceeding and is planned to close concurrently with our borrowing base redetermination in the third quarter of 2015.

Amendment to Certificate of Incorporation

At our annual stockholders meeting held on May 20, 2015, our stockholders approved an amendment to our Certificate of Incorporation to effect a 1-for-20 reverse stock split of our common stock. As a result, all stock, warrant and option transactions and per share amounts described herein have been adjusted to reflect the 1-for-20 reverse stock split.

Hedging Profile

On April 7, 2015, we entered into certain put option contracts for oil volumes produced from 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
July 2015 – December 2015		4,000	$	55.00		736,000	$	4.88	$	3,591,680
January 2016 – December 2016		3,000	$	60.00		1,098,000	$	7.54	$	8,278,920

Productive Wells

The following table summarizes gross and net productive operated and non-operated oil wells at June 30, 2015 and June 30, 2014. A net well represents our fractional working ownership interest of a gross well. The following table does not include 4 gross (3.94 net) operated Bakken and Three Forks wells that were in the process of being drilled, awaiting completion, in the process of completion or awaiting flow back subsequent to fracture stimulation as of June 30, 2015, and it does not include 12 gross (8.57 net) operated Bakken and Three Forks wells and 4 gross (0.45 net) non-operated Bakken wells that were in the process of being drilled, awaiting completion, in the process of completion or awaiting flow back subsequent to fracture stimulation as of June 30, 2014.

	June 30,
	2015				2014
	Gross		Net		Gross		Net
North Dakota Bakken and Three Forks – operated		53		41.21		28		20.91
North Dakota acquired production – operated ⁽¹⁾		43		35.68		21		15.02
Bakken and Three Forks – non-operated		49		5.46		16		2.13
Total		145		82.35		65		38.06

(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.

Results of Operations

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

	Three Months Ended June 30,
	2015			2014
REVENUES
Oil Sales	$	21,575,315		$	30,288,128
Natural Gas Sales		264,691			966,280
Net Losses on Commodity Derivatives		(4,823,936	)		(6,663,083	)
		17,016,070			24,591,325
OPERATING EXPENSES
Production Expenses		10,048,350			3,897,482
Production Taxes		2,251,080			3,400,874
General and Administrative Expenses		3,878,473			7,633,559
Depletion of Oil and Natural Gas Properties		10,034,956			8,600,878
Impairment of Oil and Natural Gas Properties		61,361,000			—
Depreciation and Amortization		167,634			81,497
Accretion of Discount on Asset Retirement Obligations		50,928			20,080
Standby Rig Expense		826,061			—
Total Operating Expenses		88,618,482			23,634,370

INCOME (LOSS) FROM OPERATIONS		(71,602,412	)		956,955

OTHER EXPENSE, NET		(1,527,000	)		(2,907,006	)

LOSS BEFORE INCOME TAXES		(73,129,412	)		(1,950,051	)

INCOME TAX EXPENSE		—			—

NET LOSS		(73,129,412	)		(1,950,051	)

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

	Three Months Ended June 30,
	2015			2014
Net Oil and Natural Gas Revenues:
Oil	$	21,575,315		$	30,288,128
Natural Gas and Other Liquids		264,691			966,280
Total Oil and Natural Gas Sales		21,840,006			31,254,408
Net Losses on Commodity Derivatives		(4,823,936	)		(6,663,083	)
Total Revenues		17,016,070			24,591,325

Oil Derivative Net Cash Settlements Paid		1,190,720			1,908,756

Net Production:
Oil (Bbl)		419,461			324,617
Natural Gas and Other Liquids (Mcf)		204,203			94,217
Barrel of Oil Equivalent (Boe)		453,495			340,320

Average Sales Prices:
Oil (per Bbl)	$	51.44		$	93.30
Effect of Settled Oil Derivatives on Average Price (per Bbl)		(2.84	)		(5.88	)
Oil Net of Settled Derivatives (per Bbl)	$	48.60		$	87.42

Natural Gas and Other Liquids (per Mcf)	$	1.30		$	10.26

Barrel of Oil Equivalent with Net Cash Settlements Paid on Commodity Derivatives (per Boe)	$	45.53		$	86.23

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

	Three Months Ended June 30,
	2015		2014
Costs and Expenses Per Boe of Production:
Production Expenses	$	18.68	$	9.90
Workover Expenses		3.47		1.55
Total Production Expenses		22.15		11.45
Production Taxes		4.96		9.99
G&A Expenses (Excluding Non-Cash Stock-Based Compensation)		7.38		13.66
Non-Cash Stock-Based Compensation		1.17		8.77
Depletion of Oil and Natural Gas Properties		22.13		25.27
Impairment of Oil and Natural Gas Properties		135.31		—
Depreciation and Amortization		0.37		0.24
Accretion of Discount on Asset Retirement Obligation		0.11		0.06
Standby Rig Expense		1.82		—

Revenues

Revenues from sales of oil and natural gas were $21.8 million for the second quarter of 2015 compared to $31.3 million for the second quarter of 2014. Our total production volumes on a Boe basis increased 33% from 340,320 Boe to 453,495 Boe in the second quarter of 2015 as compared to the second quarter of 2014. Production increased primarily due to the addition of 20.30 net productive operated Bakken/Three Forks wells since July 1, 2014. Total revenues decreased in 2015 compared to 2014 due to lower realized commodity prices during 2015. During the second quarter of 2015, we realized a $48.60 average price per Bbl of oil (including settled derivatives) compared to an $87.42 average price per Bbl of oil during the second quarter of 2014.

Net Gains (Losses) on Commodity Derivatives

Net losses on commodity derivatives were $4,823,936 during the second quarter of 2015 compared to $6,663,083 in the second quarter of 2014. Net cash settlements paid on commodity derivatives were $1,190,720 in the second quarter of 2015 compared to $1,908,756 in the second quarter of 2014. On April 7, 2015, we entered into put option contracts for oil volumes produced from May 2015 through December 2016, whereby premiums are paid monthly 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 under Item 1 in 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 June 30, 2015 and June 30, 2014, all of our derivative contracts were recorded at their fair value, which were net liabilities of $3,633,216 and $5,852,801, respectively.

Production Expenses

Production expenses were $10,048,350 for the second quarter of 2015 compared to $3,897,482 for the second quarter of 2014. Workover expenses totaling $1,575,497 were incurred in the second quarter of 2015 compared to $529,161 in the second quarter of 2014. We incurred $1,170,417 in workover rig expenses primarily attributable to producing properties acquired during 2014. On a per unit basis, production expenses increased from $9.90 per Boe sold in the second quarter of 2014 compared to $18.68 per Boe for the second quarter of 2015 when excluding workover costs. This increase in 2015 compared to 2014 was primarily due to a $1,399,807 increase in water disposal costs associated with wells scheduled to have been connected to takeaway infrastructure in the first half of 2015, a $1,062,150 increase in equipment rental costs, a $1,406,502 increase in maintenance, repairs, well servicing, and field supervision expenses and a $784,602 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.

Production Taxes

Production taxes were $2,251,080 for the second quarter of 2015 compared to $3,400,874 for the second quarter of 2014. We pay production taxes based on realized oil and natural gas sales. Our average production tax rates were 10.30% for the second quarter of 2015 compared to 10.90% for the second 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 increased production from wells with tax holiday status during the year.

General and Administrative Expense

General and administrative expenses were $3,878,473 during the second quarter of 2015 compared to $7,633,559 during the second quarter of 2014. The decrease of $3,755,086 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 $3,822,558 due to lower executive compensation, partially offset by an increase of $449,222 related to insurance and legal expense due to increased business development during the second quarter of 2015. Stock-based compensation expenses are included in employee compensation and related expenses, totaling $530,173 in the second quarter of 2015 compared to $2,983,580 in the second 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 $10,034,956 during the second quarter of 2015 compared to $8,600,878 during the second quarter of 2014. On a per-unit basis, depletion expense was $22.13 per Boe during the second quarter of 2015 compared to $25.27 per Boe during the second 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 second 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 2014 and 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 $61,361,000 of impairment expense in the second quarter of 2015 compared to $0 in the second 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 $826,061 for the second 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.

Other Expense, Net

Other expense, net was $1,527,000 for the second quarter of 2015 compared to $2,907,006 for the second quarter of 2014. We recognized a gain of $1,089,000 on the warrant liability for the second quarter of 2015 compared to an expense of $1,771,000 for the second 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 $2,616,000 for the second quarter of 2015, compared to $1,136,377 for the second quarter of 2014. The increase in interest expense primarily relates to the balance outstanding on our credit facility and increased amortization of debt issuance costs.

Net Loss

We had net loss of $73,129,412 for the second quarter of 2015 compared to $1,950,051 for the second quarter of 2014 (representing $11.70 and $0.59 per share, respectively). The increase in net loss 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 Six Months Ended June 30, 2015 with the Six Months Ended June 30, 2014

	Six Months Ended June 30,
	2015			2014
REVENUES
Oil Sales	$	35,631,347		$	48,722,936
Natural Gas Sales		729,863			1,600,344
Net Losses on Commodity Derivatives		(4,550,761	)		(7,461,936	)
		31,810,449			42,861,344
OPERATING EXPENSES
Production Expenses		17,770,504			6,514,726
Production Taxes		3,834,375			5,489,610
General and Administrative Expenses		8,673,998			16,125,563
Depletion of Oil and Natural Gas Properties		20,380,062			14,878,110
Impairment of Oil and Natural Gas Properties		146,625,000			—
Depreciation and Amortization		326,789			147,257
Accretion of Discount on Asset Retirement Obligations		100,507			35,800
Standby Rig Expense		2,372,662			—
Total Operating Expenses		200,083,900			43,191,066

LOSS FROM OPERATIONS		(168,273,451	)		(329,722	)

OTHER EXPENSE, NET		(2,518,295	)		(3,271,416	)

LOSS BEFORE INCOME TAXES		(170,791,746	)		(3,601,138	)

INCOME TAX EXPENSE		—			—

NET LOSS		(170,791,746	)		(3,601,138	)

	Six Months Ended June 30,
	2015			2014
Net Oil and Natural Gas Revenues:
Oil	$	35,631,347		$	48,722,936
Natural Gas and Other Liquids		729,863			1,600,344
Total Oil and Natural Gas Sales		36,361,210			50,323,280
Net Losses on Commodity Derivatives		(4,550,761	)		(7,461,936	)
Total Revenues		31,810,449			42,861,344

Oil Derivative Net Cash Settlements Received (Paid)		4,126,580			(2,462,140	)

Net Production:
Oil (Bbl)		824,707			538,595
Natural Gas and Other Liquids (Mcf)		318,637			165,778
Barrel of Oil Equivalent (Boe)		877,813			566,225

Average Sales Prices:
Oil (per Bbl)	$	43.20		$	90.46
Effect of Settled Oil Derivatives on Average Price (per Bbl)		5.00			(4.57	)
Oil Net of Settled Derivatives (per Bbl)	$	48.20		$	85.89

Natural Gas and Other Liquids (per Mcf)	$	2.29		$	9.65

Barrel of Oil Equivalent with Net Cash Settlements Paid on Commodity Derivatives (per Boe)	$	46.12		$	84.53

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

	Six Months Ended June 30,
	2015		2014
Costs and Expenses Per Boe of Production:
Production Expenses	$	16.10	$	10.56
Workover Expenses		4.15		0.94
Total Production Expenses		20.25		11.50
Production Taxes		4.37		9.70
G&A Expenses (Excluding Non-Cash Stock-Based Compensation)		7.42		16.68
Non-Cash Stock-Based Compensation		2.46		11.80
Depletion of Oil and Natural Gas Properties		23.22		26.28
Impairment of Oil and Natural Gas Properties		167.03		—
Depreciation and Amortization		0.37		0.26
Accretion of Discount on Asset Retirement Obligation		0.11		0.06
Standby Rig Expense		2.70		—

Revenues

Revenues from sales of oil and natural gas were $36.4 million for the first half of 2015 compared to $50.3 million for the first half of 2014. Our total production volumes on a Boe basis increased 55% from 566,225 Boe in the first half of 2014 to 877,813 Boe in the first half of 2015. Production increased primarily due to the addition of 20.30 net productive operated Bakken/Three Forks wells since July 1, 2014. . Total revenues decreased in 2015 compared to 2014 due to lower realized commodity prices during 2015. During the first half of 2015, we realized an $48.20 average price per Bbl of oil (including settled derivatives) compared to an $85.89 average price per Bbl of oil during the first half of 2014.

Net Losses on Commodity Derivatives

Net losses on commodity derivatives were $4,550,761 during the first half of 2015 compared to $7,461,936 in the first half of 2014. Net cash settlements received on commodity derivatives were $4,126,580 in the first half of 2015 compared to $2,462,140 paid in the first half 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 premiums are paid monthly 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 under Item 1 in 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 June 30, 2015 and June 30, 2014, all of our derivative contracts were recorded at their fair value, which was a net liability of $3,633,216 and $5,852,801, respectively.

Production Expenses

Production expenses were $17,770,504 for the first half of 2015 compared to $6,514,726 for the first half of 2014. Workover expenses totaling $3,641,534 were incurred in the first half of 2015 compared to $533,026 in the first half of 2014. The increase is primarily due to workover rig charges of $1,459,251, artificial lift expenses of $594,615, and tubing and rod replacements of $341,495. A portion of the increase in workover expense was attributable to producing properties acquired during 2014. We experience increases in production expenses as we add new wells and maintain production from existing properties and well count was higher by 44 net wells (116% increase) compared to the same prior year period . On a per unit basis, production expenses increased from $11.50 per Boe in the first half of 2014 compared to $20.25 per Boe for the first half of 2015 when including workover costs. This increase in 2015 compared to 2014 was primarily due to a $2,330,309 increase in water disposal costs associated with wells scheduled to have been connected to takeaway infrastructure in the first half of 2015, a $1,845,059 increase in equipment rental costs, a $2,269,968 increase in maintenance, repairs, well servicing, and field supervision expenses and a $1,028,936 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.

Production Taxes

Production taxes were $3,834,375 for the first half of 2015 compared to $5,489,610 for the first half of 2014. We pay production taxes based on realized oil and natural gas sales. Our average production tax rates were 10.55% for the first half of 2015 compared to 10.91% for the first half 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 increased production from wells with tax holiday status during the year.

General and Administrative Expense

General and administrative expenses were $8,673,998 during the first half of 2015 compared to $16,125,563 during the first half of 2014. The decrease of $7,451,565 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 $7,671,911 due to lower executive compensation, offset by an increase of $650,871 related to insurance and legal expense due to increased business development during 2015. Stock-based compensation expenses are included in the employee compensation and related expenses, totaling $2,163,753 in the first half of 2015 compared to $6,678,883 in the first half 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 $20,380,062 during the first half of 2015 compared to $14,878,110 during the first half of 2014. On a per-unit basis, depletion expense was $23.22 per Boe during the first half of 2015 compared to $26.28 per Boe during the first half 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 half of 2015 compared to the first half of 2014 on a per unit basis was due primarily to a lower depletable base as a result of the impairment expense recognized in 2014 and 2015.

Impairment of Oil and Natural Gas Properties

We recognized $146,625,000 of impairment expense in the first half of 2015 compared to $0 in the first half of 2014. The impairment expense is primarily due to the reduction in the price of crude oil beginning in the fourth quarter of 2014.

Standby Rig Expense

Standby rig expenses totaled $2,372,662 for the first half 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.

Other Expense, Net

Other expense, net was $2,518,295 for the first half of 2015 compared to $3,271,416 for the first half of 2014. We recognized a gain of $1,791,000 on the warrant liability for the first half of 2015 compared to an unrealized loss of $1,967,000 for the first half 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 $4,309,552 for the first half of 2015, compared to $1,308,463 for the first half of 2014. The increase in interest expense primarily relates to the balance outstanding on our credit facility and increased amortization of debt issuance costs.

Net Loss

We had net loss of $170,791,746 for the first half of 2015 compared to $3,601,138 for the first half of 2014 (representing $(31.18) and $(1.09) per share-basic, respectively). The increase in net loss 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 June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
Net loss	$	(73,129,412	)	$	(1,950,051	)	$	(170,791,746	)	$	(3,601,138	)
Impairment of oil and natural gas properties		61,361,000			—			146,625,000			—
Interest expense		2,616,000			1,136,377			4,309,552			1,308,463
Accretion of discount on asset retirement obligations		50,928			20,080			100,507			35,800
Depletion, depreciation and amortization		10,202,590			8,682,375			20,706,851			15,025,367
Stock-based compensation		530,173			2,983,580			2,163,753			6,678,883
Warrant revaluation (gain) expense		(1,089,000	)		1,771,000			(1,791,000	)		1,967,000
Net losses on commodity derivatives		4,823,936			6,663,083			4,550,761			7,461,936
Net cash settlements received (paid) on commodity derivatives		(1,190,720	)		(1,908,756	)		4,126,580			(2,462,140	)
Standby rig expense		826,061			—			2,372,665			—
Adjusted EBITDA	$	5,001,556		$	17,397,688		$	12,372,923		$	26,414,171

Liquidity and Capital Resources

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

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

Current assets	$	45,601,580
Current liabilities		382,223,888
Working capital	$	(336,622,308	)

Equity Offerings

On February 11, 2015, the Company 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.

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 April and May 2015, we issued an aggregate 2,460,045 shares of common stock through our continuous at-the-market offering program at an average price of $6.87 per share for total net proceeds of approximately $16.4 million.

Credit Facility

On November 20, 2012, we entered into a senior secured revolving credit facility (the “Credit Facility”) with Wells Fargo Bank, N.A., as administrative agent (“Wells Fargo”), and the lenders party thereto. 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 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 June 30, 2015, we had drawn approximately $160 million toward its $200 million borrowing base under the Credit Facility.

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 June 30, 2015, the annual interest rate on the Credit Facility was 2.82%.

A portion of the Credit Facility not in excess of $5 million will be available for the issuance of letters of credit by Wells Fargo. We will pay a rate per annum ranging from 1.75% to 2.75% on the face amount of each letter of credit issued and will pay a fronting fee equal to the greater of $500 and 0.125% of the face amount of each letter of credit issued. As of June 30, 2015, we had 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 our guarantors, including a pledge of their ownership in their respective subsidiaries.

The Credit Facility contains customary covenants that include, among other things: limitations on 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. We were not in compliance with the total debt to EBITDA and Senior Secured Debt-to-EBITDA ratios under the Credit Facility as of June 30, 2015. We have been in discussions with our lending group regarding amending the leverage ratio covenants during the upcoming scheduled borrowing base redetermination, which discussions began in July 2015. Based on those discussions, our lending group has agreed in principle to adjust the covenants to provide for more flexibility given lower forecasted adjusted EBITDA due to the lower commodity price environment. Our borrowing base will be reduced as a result of this redetermination. A resultant breach of the covenants under the Credit Facility could cause a default under the reserve based 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 due in 2019 and permit the holders of those notes to accelerate their maturity. We anticipate the execution of this redetermination in the third quarter of 2015. In accordance with the provisions under ASC 470-10-45-1, we have classified the balance of the Credit Facility as a current liability as of June 30, 2015. Upon closing the amendment to the Credit Facility in the third quarter of 2015, we expect to reclassify the Credit Facility to a long term liability. Please see Item 2. Recent Developments of this report for further information regarding changes to covenants and financing arrangements subsequent to June 30, 2015.

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

Satisfaction of Our Cash Obligations for the Next Twelve Months

We project we will have sufficient capital to accomplish our development plan and forecasted general and administrative expenses for the next twelve months. 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. Our 2015 production and capital expenditure estimates are now based upon a variable one-rig drilling program. Our projections are based on cash on hand, our expected cash flow from operations, expected proceeds from the acreage sale to Koch, expected amendment and borrowing capacity under our Credit Facility and proceeds from the closing of our anticipated term loan. However, we may scale back our development plan should our projections of cash flow and borrowing capacity fall short of expectations or commodity prices remain depressed or decline further. We may also attempt to access the equity or debt capital markets to fund acreage acquisitions and/or accelerated drilling at the discretion of management, depending on prevailing market conditions. We will evaluate any potential opportunities for acquisitions as they arise and meet our strategic objectives. We believe we are in a position to take advantage of any appropriately priced acquisition opportunities that may arise. However, there can be no assurance that any additional capital will be available to us on favorable terms or at all. See Part II—Other Information—Item IA. Risk Factors.

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 Item 1. Financial Statements – Note 2 Basis of Presentation and Significant Accounting Policies for our methodology for valuing commodity derivative instruments.

Cash and Cash Equivalents

Our total cash resources as of June 30, 2015 were $19,116,956, compared to $12,389,230 as of December 31, 2014. The increase in our cash balance was primarily attributable to cash flow from operations, the equity offering completed in February 2015, issuances under our continuous offering program and borrowings under our Credit Facility, offset by the development of oil and natural gas properties.

Net Cash Provided By Operating Activities

Net cash provided by operating activities was $13,588,411 for the first half of 2015 compared to $19,894,739 for the first half of 2014. The change in the net cash provided by operating activities is primarily attributable to lower revenues due to commodity price, higher production expenses and other operating expenses.

Net Cash Used For Investment Activities

Net cash used in investment activities was $136,523,000 for the first half of 2015 compared to $196,457,501 for the first half of 2014. The change in net cash used in investment activities for the first half 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 $129,662,315 for the first half of 2015 compared to $166,478,991 for the first half of 2014. The change in net cash provided by financing activities for the first half of 2015 is primarily attributable to proceeds from the equity offering in February 2015 and borrowings under our Credit Facility and the issuance of the Convertible Notes in March 2014.

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 six-month period ended June 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 and in our Quarterly Report on Form 10-Q for the three months ended March 31, 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;

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

competition, including competition for acreage in resource play areas;

our ability to retain key members of management;

volatility in commodity prices for oil and natural gas;

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

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

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.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

The price we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile, and these markets will likely continue to be volatile in the future. The prices we receive for our production depend on numerous factors beyond our control. Our revenues during the three and six months ended June 30, 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.

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 June 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 liability by approximately $2.1 million.

Interest Rate Risk

At June 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 June 30, 2015, we had $200 million of total borrowings available to us under our Credit Facility, of which approximately $160 million was drawn at June 30, 2015. The Credit Facility bears interest at variable rates. Assuming we had the maximum amount outstanding at June 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 under Item 1 in this Quarterly Report.

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 June 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

We may be subject to litigation claims and governmental and regulatory proceedings arising in the ordinary course of business. These claims and proceedings are subject to uncertainties inherent in any litigation matters and proceedings. However, we believe that all such litigation matters and proceedings that may arise in the ordinary course are not likely to have a material adverse effect on our financial position, cash flows or results of operations.

ITEM 1A. RISK FACTORS

Our business is subject to a number of risks, some of which are beyond our control. In addition to the other information set forth in this report, you should carefully consider the factors discussed in Item 1A –“Risk Factors” of our Annual Report on Form 10-K for the fiscal year ended December 31, 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, that could have a material adverse effect on our business, results of operations, financial condition and/or liquidity and that could cause our operating results to vary significantly from period to period. As of June 30, 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 Report on Form 10-Q for the three months ended March 31, 2015, 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.

We are exposed to fluctuations in the price of oil and natural gas, and our hedging program may be inadequate to protect us against continuing and prolonged declines in the price of oil and natural gas.

At June 30, 2015, we had commodity price derivative agreements on approximately 4,000 Bbls/d of oil hedged with fixed price swaps through the end of 2016. These hedges may be inadequate to protect us from continuing and prolonged decline in the price of oil and natural gas. To the extent that the prices of oil and natural gas remain at current levels or decline further, we will not be able to hedge future production at the same level as our current hedges and our results of operations and financial condition would be negatively impacted.

Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage.

A large portion of our acreage is not currently held by production. Unless production in paying quantities is established on units containing these leases during their terms, these leases will expire. If our leases expire, we will lose our right to develop the related properties. In addition, because of our concerns regarding the effect that continued deterioration in commodity prices could have on the economics of drilling our Bakken acreage, we have reduced our planned drilling activity on this acreage in 2015. To the extent we are unable to begin production in paying quantities on the acreage whose applicable lease is scheduled to expire in 2015, those leases will expire. Less than 1% of our acreage in the Williston Basin is scheduled to expire during the remainder of 2015. Our drilling plans for these areas are subject to change based upon various factors, many of which are beyond our control, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints, and regulatory approvals. Further, some of our acreage is located in sections where we do not hold the majority of the acreage and therefore it is likely that we will not be named operator of these sections. On our acreage that we do not operate, we have less control over the timing of drilling and there is therefore additional risk of expirations occurring in those sections.

We may be subject to a redetermination of the borrowing base under our revolving 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 revolving credit facility on a quarterly basis, and as of June 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 revolving credit facility is not amended or waived.

Our revolving 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. 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 a reduction in our borrowing base at the next redetermination, which was scheduled to occur in October 2015, but has been accelerated to August 2015 in concurrence with the closing of the Term Loan and we expect our borrowing base to be reduced as a result of this determination.

We would anticipate prolonged depression of pricing may equate to 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.

A reduction in our borrowing base could require us to repay any indebtedness in excess of the borrowing base. 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 revolving 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 June 30, 2015. We have been in discussions with our lending group regarding amending the leverage ratio covenants during the upcoming scheduled borrowing base redetermination, which discussions began in July 2015. Based on those discussions, our lending group has agreed in principle to adjust the covenants to provide for more flexibility given lower forecasted adjusted EBITDA due to the lower commodity price environment. A resultant breach of the covenants under our revolving credit facility could cause a default under the reserve based 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 due 2019 and permit the holders of those notes to accelerate their maturity. Our inability to close the amendment to the reserve based credit agreement 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.

We have significantly reduced our drilling and completion operations in the Bakken Shale because such activities are currently economically challenging in the current crude oil price environment. Considering lower commodity prices and persistent differentials in that area, we do not anticipate material improvement in realized margins from drilling and completion operations for the foreseeable future.

In the fourth quarter of 2014 and continuing into 2015, the price of crude oil dropped substantially. Additionally, pricing differentials have persisted close to historical levels. At current crude oil price levels, pricing differentials and production cost levels, our drilling and completion operations in the Bakken Shale are economically challenging. While we continue to produce oil and gas from existing wells and continue to drill wells to hold our leasehold acreage by production, we do not anticipate our cash margins on production from this acreage to improve materially in the current pricing and differentials environment. Consequently, we do not anticipate resuming at prior levels our drilling and completion activities on this acreage in the near future. Our ability to achieve increased margins for our operations in the Bakken Shale will largely depend on rising commodity prices, which are beyond our control.

Proposed changes to U.S. tax laws, if adopted, could have an adverse effect on our business, financial condition, results of operations and cash flows.

The U.S. President’s Fiscal Year 2016 Budget Proposal includes provisions that would, if enacted, make significant changes to U.S. tax laws. These changes include, but are not limited to, eliminating the immediate deduction for intangible drilling and development costs, eliminating the deduction from income for domestic production activities relating to oil and natural gas exploration and development, repealing the percentage depletion allowance for oil and natural gas properties and extending the amortization period for certain geological and geophysical expenditures. These proposed changes in the U.S. tax laws, if adopted, or other similar changes that reduce or eliminate deductions currently available with respect to oil and natural gas exploration and development, could adversely affect our business, financial condition, results of operations and cash flows.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing legislation could result in increased costs and additional operating restrictions or delays, or restrict our access to oil and natural gas reserves.

We currently use hydraulic fracturing in our operations. Hydraulic fracturing typically involves the injection under pressure of water, sand and additives into rock formations in order to stimulate hydrocarbon production. Hydraulic fracturing using fluids other than diesel is currently exempt from regulation under the federal Safe Drinking Water Act (SDWA), but opponents of hydraulic fracturing have called for further study of the technique’s environmental effects and, in some cases, a moratorium on the use of the technique. Several proposals have been submitted to Congress that, if implemented, would subject all hydraulic fracturing to regulation under the SDWA. Eliminating this exemption could establish an additional level of regulation and permitting at the federal level that could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our cost of compliance and doing business. In addition, the EPA’s Office of Research and Development is conducting a scientific study to investigate the possible relationships between hydraulic fracturing and drinking water. In June 2015, the EPA issued its draft report, and while the report stated that, “there are above- and below-ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water resources,” the EPA stated that, “it did not find evidence that these mechanisms have led to widespread, systemic impacts on drinking water resources in the United States.”

Even in the absence of new legislation, the EPA recently asserted the authority to regulate hydraulic fracturing involving the use of diesel additives under the SDWA’s Underground Injection Control Program (UIC Program), which regulates the underground injection of substances. On February 12, 2014, the EPA published UIC Program guidance for oil and natural gas hydraulic fracturing activities using diesel fuel. The guidance document is designed for use by employees of the EPA that draft the UIC permits and describes how regulations of Class II wells, which are those wells injecting fluids associated with oil and natural gas production activities, may be tailored to address the purported unique risks of diesel fuel injection during the hydraulic fracturing process. The EPA has encouraged state programs to review and consider use of the above mentioned guidance. To the extent that EPA’s new regulatory guidance is extended to our operations by permitting authorities, additional and significant compliance costs may arise that could materially affect our operations, cash flows, and financial position. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards sometime in 2015. Also, in May 2014, the EPA issued an Advanced Notice of Proposed Rulemaking under the Toxic Substances Control Act that would require companies to disclose information regarding the chemicals used in hydraulic fracturing.

Hydraulic fracturing operations require the use of water and the disposal or recycling of water that has been used in operations. The federal Clean Water Act (CWA) restricts the discharge of produced waters and other pollutants into waters of the United States and requires permits before any pollutants may be so discharged. Pursuant to the CWA, the EPA has announced its intention to propose regulations during 2015 for wastewater discharges from hydraulic fracturing and certain other natural gas operations. The CWA and comparable state laws and regulations provide for penalties for unauthorized discharges of pollutants including produced water, oil, and other hazardous substances. Compliance with and future revisions to requirements and permits governing the use, discharge, and recycling of water used for hydraulic fracturing may increase our costs and cause delays, interruptions or terminations of our operations which cannot be predicted.

In March 2015, the Bureau of Land Management of the Department of Interior proposed stringent regulations regarding the use of hydraulic fracturing on federal lands. These regulations were scheduled to be effective on June 24, 2015, however, a federal judge has granted a temporary stay against implementation pending further proceedings and hearings on a request for a preliminary injunction of the rules. While these regulations only apply to federal lands, where we do not operate, it is believed that if they are effective, some states could implement similar regulations and larger oil and gas companies may change their operations on all projects to be consistent with the federal guidelines. The Department of Energy, moreover, has developed its own recommendations for actions to lessen the environmental impact associated with hydraulic fracturing operations.

Apart from federal regulatory initiatives, states have been considering or implementing new requirements for hydraulic fracturing, including restricting its use in environmentally sensitive areas. Similarly, some localities have significantly limited or prohibited drilling activities, or are considering doing so. In addition, there have been proposals by non-governmental organizations to restrict certain buyers from purchasing oil and natural gas produced from wells that have utilized hydraulic fracturing in their completion process, which could negatively impact our ability to sell our production from wells that utilized these fracturing processes.

It is not possible at this time to predict the final requirements of any additional federal or state legislation or regulation regarding hydraulic fracturing. Any new federal, state, or local restrictions on hydraulic fracturing that may be imposed in areas where we conduct business, such as the Bakken and Three Forks areas, however, could result in delays, eliminate certain drilling and injection activities, make it more difficult or costly for us to perform hydraulic fracturing, significantly increase our costs of compliance and doing business, and delay or prevent the development of unconventional hydrocarbon resources from shale and other formations that are not commercial without the use of hydraulic fracturing.

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)

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)

4.1

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

10.1

Amendment to the Amended and Restated Credit Agreement, dated as of April 30, 2015, among Emerald Oil, Inc., Wells Fargo Bank, N.A., as Administrative Agent, and the Lenders party thereto (filed as Exhibit 10.1 to the Company’s Quarterly Form 10-Q filed on May 4, 2015, and incorporated herein by reference)

10.2

Emerald Oil, Inc. Third Amended and Restated 2011 Equity Incentive Plan (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on May 20, 2015, and incorporated herein by reference)

10.3

At-The-Market Issuance Sales Agreement, dated April 2, 2015, by and between Emerald Oil, Inc. and MLV & Co. LLC (filed as Exhibit 1.1 to the Company’s Current Report on Form 8-K filed on April 2, 2015, and incorporated herein by reference)

10.4

At-The-Market Issuance Sales Agreement, dated April 2, 2015, by and between Emerald Oil, Inc. and USCA Securities LLC (filed as Exhibit 1.2 to the Company’s Current Report on Form 8-K filed on April 2, 2015, and incorporated herein by reference)

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.

SIGNATURES

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

Dated: August 4, 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)