UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2015

OR

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

For the transition period from                  to

Commission File No. 1-35097

Emerald Oil, Inc.

(Exact name of registrant as specified in its charter)

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

200 Columbine Street, Suite 500
Denver, CO	80206
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (303) 595-5600

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x  No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x  No ¨

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

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

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

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

EMERALD OIL, INC.

INDEX

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

PART 1 — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

EMERALD OIL, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

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

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

1

EMERALD OIL, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

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

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

2

EMERALD OIL, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

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

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

3

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

NOTE 1  ORGANIZATION AND NATURE OF BUSINESS

Description of Operations —  Emerald Oil, Inc., a Delaware corporation (“Emerald,” the “Company,” “we,” “us” or “our”), is a Denver-based independent exploration and production company focused on acquiring acreage and developing oil and natural gas wells in the Williston Basin of North Dakota and Montana. The Company designs, drills and operates oil and natural gas wells on acreage where it holds a controlling working interest. The Company also participates in the drilling of oil and natural gas wells operated by other companies.

NOTE 2  BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES

The accompanying condensed consolidated financial statements have been prepared on the accrual basis of accounting whereby revenues are recognized when earned and expenses are recognized when incurred. The condensed consolidated financial statements as of September 30, 2015 and for the three and nine months ended September 30, 2015 and 2014 are unaudited. In the opinion of management, such financial statements include the adjustments and accruals that are of a normal recurring nature and necessary for a fair presentation of the results for the interim periods. The interim results are not necessarily indicative of results for a full year. Certain information and footnote disclosures normally included in financial statements prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) have been condensed or omitted in these condensed consolidated financial statements as of September 30, 2015 and for the three and nine months ended September 30, 2015 and 2014.

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

Reverse Stock Split

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

Cash and Cash Equivalents

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

Restricted Cash

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

4

Accounts Receivable

The Company records estimated oil and natural gas revenue receivable from third parties at its net revenue interest. The Company also reflects costs incurred on behalf of joint interest partners in accounts receivable. Management periodically reviews accounts receivable amounts for collectability and records its allowance for uncollectible receivables under the specific identification method. The Company did not record any allowance for uncollectible receivables during the three and nine months ended September 30, 2015 and 2014.

Full Cost Method

The Company follows the full cost method of accounting for oil and natural gas operations whereby all costs related to the exploration and development of oil and natural gas properties are initially capitalized into a single cost center (“full cost pool”). Such costs include land acquisition costs, a portion of employee salaries related to property development, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisitions, and exploration activities. For the three months ended September 30, 2015 and 2014, the Company capitalized $814,011 and $1,354,556, respectively, of internal salaries, which included $78,390 and $624,629, respectively, of stock-based compensation. For the nine months ended September 30, 2015 and 2014, the Company capitalized $3,245,667 and $4,278,105, respectively, of internal salaries, which included $708,600, and $2,020,992, respectively, of stock-based compensation. Internal salaries are capitalized based on employee time allocated to the acquisition of leaseholds and development of oil and natural gas properties. The Company capitalized no interest in the three and nine months ended September 30, 2015 and 2014.

Proceeds from property sales will generally be credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. No gain or loss was recognized on any sales during the three and nine months ended September 30, 2015 and 2014. The Company engages in acreage trades in the Williston Basin, but these trades are generally for acreage that is similar both in terms of geographic location and potential resource value.

The Company assesses all items classified as unproved property on a quarterly basis for possible impairment or reduction in value. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves, and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion and amortization. For the nine months ended September 30, 2015 and the year ended December 31, 2014, the Company included $15,231,547 and $2,979,258, respectively, related to expiring leases within costs subject to the depletion calculation.

Capitalized costs associated with impaired properties and properties having proved reserves, estimated future development costs, and asset retirement costs under Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 410-20-25 are depleted and amortized on the unit-of-production method based on the estimated gross proved reserves. The costs of unproved properties are withheld from the depletion base until such time as they are developed, impaired or abandoned.

Under the full cost method of accounting, capitalized oil and natural gas property costs less accumulated depletion, net of deferred income taxes, may not exceed a ceiling amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and natural gas reserves plus the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unproved properties that are subject to amortization. Should capitalized costs exceed this ceiling, which is tested on a quarterly basis, an impairment is recognized. The present value of estimated future net revenues is computed by applying prices based on a 12-month unweighted average of the oil and natural gas prices in effect on the first day of each month, less estimated future expenditures to be incurred in developing and producing the proved reserves (assuming the continuation of existing economic conditions), less any applicable future taxes. Any required write-downs are included in the consolidated statement of operations as an impairment charge. Based on calculated reserves at September 30, 2015, the unamortized costs of the Company’s oil and natural gas properties exceeded the ceiling test limit by $158,278,000. As a result, the Company was required to record impairments of the net capitalized costs of its oil and natural gas properties in the amount of $158,278,000 and $304,903,000 for the three and nine months ended September 30, 2015, respectively. As of September 30, 2014, the unamortized costs of the Company’s oil and natural gas properties did not exceed the ceiling test limit and no impairment expense was recognized for the three and nine months ended September 30, 2014.

Other Property and Equipment

Property and equipment that are not oil and natural gas properties are recorded at cost and depreciated using the straight-line method over their estimated useful lives of three to seven years. Expenditures for replacements, renewals, and betterments are capitalized. Maintenance and repairs are charged to expense as incurred.

5

ASC 360-10-35-21 requires that long-lived assets, other than oil and natural gas properties, be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The determination of impairment is based upon expectations of undiscounted future cash flows, before interest, of the related asset. If the carrying value of the asset exceeds the undiscounted future cash flows, the impairment would be computed as the difference between the carrying value of the asset and the fair value. The Company has not recognized any impairment losses on non-oil and natural gas long-lived assets.

Asset Retirement Obligations

The Company records the fair value of a liability for an asset retirement obligation in the period in which it can be reasonably estimated or the asset is acquired and a corresponding increase in the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depleted using the units of production method. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.

Revenue Recognition and Natural Gas Balancing

The Company recognizes oil and natural gas revenues from its interests in producing wells when production is delivered and title has transferred to the purchaser, to the extent the selling price is reasonably determinable. The Company uses the sales method of accounting for balancing of natural gas production and would recognize a liability if the existing proved reserves were not adequate to cover the current imbalance situation. As of September 30, 2015 and December 31, 2014, the Company’s natural gas production was in balance, i.e., its cumulative portion of natural gas production taken and sold from wells in which it has an interest equaled the Company’s entitled interest in natural gas production from those wells.

Stock-Based Compensation

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

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

Income Taxes

The Company accounts for income taxes under ASC 740-10-30. Deferred income tax assets and liabilities are determined based upon differences between the financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse. Accounting standards require the consideration of a valuation allowance for deferred tax assets if it is “more likely than not” that some component or all of the benefits of deferred tax assets will not be realized.

6

The tax effects from an uncertain tax position can be recognized in the financial statements only if the position is more likely than not of being sustained if the position were to be challenged by a taxing authority. The Company has examined the tax positions taken in its tax returns and determined that there are no uncertain tax positions. As a result, the Company has recorded no uncertain tax liabilities in its condensed consolidated balance sheet.

Net Income (Loss) Per Common Share

Basic net income (loss) per common share is based on the net income (loss) divided by the weighted average number of shares of common stock outstanding during the period. Diluted earnings per share are computed using the weighted average number of shares of common stock plus dilutive common share equivalents outstanding during the period using the treasury stock method. In the computation of diluted earnings per share, excess tax benefits that would be created upon the assumed vesting of nonvested restricted shares or the assumed exercise of stock options (i.e., hypothetical excess tax benefits) are included in the assumed proceeds component of the treasury stock method to the extent that such excess tax benefits are more likely than not to be realized. When a loss from continuing operations exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share. As the Company had losses for the three and nine months ended September 30, 2015 and 2014, the potentially dilutive shares were anti-dilutive and were thus not included in the net loss per share calculation.

As of September 30, 2015, (i) 72,092 nonvested restricted stock units were issued and outstanding and represent potentially dilutive shares; (ii) 30,759 stock options were issued and presently exercisable and represent potentially dilutive shares; (iii) 9,777 stock options were granted but were not presently exercisable and represent potentially dilutive shares; (iv) 255,732 warrants were issued and presently exercisable, which have an exercise price of $9.52 and represent potentially dilutive shares; (v) 11,165 warrants were issued and presently exercisable, which have an exercise price of $137.20 and represent potentially dilutive shares; (vi) 44,643 warrants were issued and presently exercisable, which have an exercise price of $994.00 and represent potentially dilutive shares; and (vii) $151.5 million of Convertible Notes were convertible into approximately 863,248 shares of common stock as of September 30, 2015 and represent potentially dilutive shares.

Derivative and Other Financial Instruments

Commodity Derivative Instruments

The Company has entered into commodity derivative instruments, utilizing oil derivative swap contracts to reduce the effect of price changes on a portion of future oil production. The Company’s commodity derivative instruments are measured at fair value and are included in the consolidated balance sheet as derivative assets and liabilities. Net gains and losses are recorded based on the changes in the fair values of the derivative instruments. The Company’s valuation estimate takes into consideration the counterparties’ creditworthiness, the Company’s creditworthiness, and the time value of money. The consideration of the factors results in an estimated exit price for each derivative asset or liability under a marketplace participant’s view. Management believes that this approach provides a reasonable, non-biased, verifiable, and consistent methodology for valuing commodity derivative instruments (see Note 13 – Derivative Instruments and Price Risk Management).

Warrant Liability

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

As a part of a securities purchase agreement entered into in February 2013 with affiliates of White Deer Energy L.P. (see Note 6 – Preferred and Common Stock), the Company issued warrants that contain a put and other liability type provisions. Accordingly, these warrants are accounted for as a liability. This warrant liability is accounted for at fair value with changes in fair value reported in the consolidated statement of operations.

New Accounting Pronouncements

From time to time, new accounting pronouncements are issued by FASB that are adopted by the Company as of the specified effective date.  If not discussed, management believes that the impact of recently issued standards, which are not yet effective, will not have a material impact on the Company’s consolidated financial statements upon adoption.

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Use of Estimates

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

Industry Segment and Geographic Information

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

Reclassifications

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

NOTE 3 LIQUIDITY AND CAPITAL RESOURCES

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

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

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

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

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

NOTE 4  OIL AND NATURAL GAS PROPERTIES

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

Joint Venture Agreement

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

Acquisitions

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

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

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

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Pro Forma Operating Results

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

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

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

NOTE 5  RELATED PARTY TRANSACTIONS

In February 2013, the Company entered into a securities purchase agreement (the “Securities Purchase Agreement”) with affiliates of White Deer Energy L.P. (“White Deer Energy”), pursuant to which the Company issued to White Deer Energy 500,000 shares of Series A Perpetual Preferred Stock (“Series A Preferred Stock”), 255,732 shares of Series B Voting Preferred Stock (“Series B Preferred Stock”) and warrants to purchase an initial aggregate amount of 255,732 shares of the Company’s common stock at an initial exercise price of $115.40 per share, for an aggregate $50 million. Pursuant to the Securities Purchase Agreement, White Deer Energy obtained the right to designate one member of the Company’s board of directors as long as White Deer Energy held any shares of Series A Preferred Stock. White Deer Energy designated Thomas J. Edelman as its initial director. Following the redemption of the Series A Preferred Stock during 2013, the Governance and Nominating Committee of the Company nominated Mr. Edelman to continue to serve as a director of the Company, and Mr. Edelman was elected to serve on the board of directors of the Company for another term at the annual stockholders meeting of the Company held in June 2014. On January 28, 2015, Mr. Edelman resigned from his position as a director of the Company and Ben Guill, a Managing Partner of White Deer Energy, was appointed to the Board of Directors. For additional information regarding the Securities Purchase Agreement with White Deer Energy, see Note 6 — Preferred and Common Stock.

The transaction was subject to customary closing conditions, as well as the execution and delivery of certain other agreements, including a registration rights agreement. Under the terms of the registration rights agreement, as amended, the Company agreed to file with the Securities and Exchange Commission (the “SEC”), within 30 days upon receipt of notice from White Deer Energy, a shelf registration statement covering resales of the 255,732 shares of Company common stock issuable upon exercise of the warrants and use commercially reasonable efforts to cause such registration statement to be declared effective within 120 days after the filing thereof. In June 2013 and October 2013, the Company amended the registration rights agreement to include 139,280 shares of Company common stock and 254,643 shares of Company common stock, respectively, issued to White Deer Energy in connection with subsequent private placements. On April 19, 2014, the Company received a request from White Deer Energy to register the shares of Company common stock and the shares of Company common stock underlying the warrants held by White Deer Energy.  On May 16, 2014, the Company filed with the SEC a registration statement on Form S-3 to register for resale the 393,923 shares of common stock and 255,732 shares of common stock underlying the warrants held by White Deer Energy, and the SEC declared the registration statement effective on May 30, 2014. In February 2015, the Company completed a public offering of 1,357,955 shares of common stock at a price of $22.40 per share for total net proceeds of approximately $29.4 million. White Deer Energy purchased 669,643 common shares in the public offering. White Deer Energy’s participation in the public offering was approved by the Company’s board of directors.

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NOTE 6  PREFERRED AND COMMON STOCK

Preferred Stock

On February 19, 2013, the Company issued to White Deer Energy 500,000 shares of Series A Preferred Stock, 255,732 shares of Series B Preferred Stock and warrants to purchase an initial aggregate 255,732 shares of the Company’s common stock at an initial exercise price of $115.40 per share, in exchange for an aggregate $50 million. The warrants are exercisable until December 31, 2019.

On various dates throughout 2013, the Company redeemed all of the outstanding shares of Series A Preferred Stock, including the $50,000,000 principal and redemption premiums of $6,250,000, and no shares of Series A Preferred Stock remained outstanding as of September 30, 2015. For each redemption, the redemption premium was treated as a dividend and recorded as a return of equity to White Deer Energy through a charge to the Company’s additional paid-in capital. The Company paid no dividends during the three and nine months ended September 30, 2015 and 2014.

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

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

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

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

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

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

Equity Issuances

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

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

Restricted Stock Awards and Restricted Stock Unit Awards

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

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

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

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NOTE 7  STOCK OPTIONS AND WARRANTS

Stock Options

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

The impact on the Company’s condensed consolidated statement of operations of stock-based compensation expense related to options granted for the three months ended September 30, 2015 and 2014 was $(15,200) and $337,809, respectively, net of forfeitures, cancellations and $0 tax. The impact on the Company’s condensed consolidated statement of operations of stock-based compensation expense related to options granted for the nine months ended September 30, 2015 and 2014 was $142,276 and $810,419, respectively, net of forfeitures, cancellations and $0 tax. The Company capitalized $(5,035), and $187,017 in compensation to oil and natural gas properties related to outstanding options for the three months ended September 30, 2015 and 2014, respectively, and $106,995 and $595,628  for the nine months ended September 30, 2015 and 2014, respectively. The Company had $183,140 of total unrecognized compensation cost related to nonvested stock options granted as of September 30, 2015. The remaining cost is expected to be recognized over a weighted-average period of 0.89 years. These estimates are subject to change based on a variety of future events that include, but are not limited to, changes in estimated forfeiture rates, cancellations and the issuance of new options.

A summary of the stock options activity during the nine months ended September 30, 2015 is as follows:

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

At September 30, 2015, stock options outstanding were as follows:

	Options Outstanding						Options Exercisable
Year of Grant	Number of Options Outstanding		Weighted Average Remaining Contract Life (years)		Weighted Average Exercise Price		Number of Options Exercisable		Weighted Average Remaining Contract Life (years)		Weighted Average Exercise Price
2015		—		—		—		—		—		—
2014		15,781		3.18	$	143.48		8,804		2.98	$	145.17
2013		8,755		3.36		140.95		5,955		2.92		139.27
2012		14,731		1.82		156.80		14,731		1.82		156.80
Prior		1,269		2.97		174.96		1,269		2.97		174.96
Total		40,536		2.72	$	148.78		30,759		2.41	$	150.83

Warrants

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

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

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

NOTE 8 REVOLVING CREDIT FACILITY

Wells Fargo Facility

On November 20, 2012, the Company entered into a senior secured revolving credit facility (as amended, the “Credit Facility”) with Wells Fargo Bank, N.A., as administrative agent (“Wells Fargo”), and the lenders party thereto. The Credit Facility is a senior secured reserve-based revolving credit facility with a maximum commitment of $400 million. On April 30, 2015, in connection with the semi-annual borrowing base redetermination, the Company and its lending group entered into an amendment to the Credit Facility. The amendment to the Credit Facility reduced the borrowing base from $250 million to $200 million. As of September 30, 2015, the Company had drawn approximately $160 million toward its $200 million borrowing base under the Credit Facility. The Company’s borrowing base under its Credit Facility was subject to its semi-annual redetermination on October 6, 2015, and the lenders decreased the borrowing base to $120 million. This redetermination resulted in an outstanding deficiency under the Credit Facility of approximately $19.6 million. Under the terms of the Credit Agreement, the Company is permitted to repay the deficiency in three monthly installments beginning 30 days after the date of the redetermination. The Company does not expect to be able to make the monthly installments, which will result in a default under the Credit Agreement. The Credit Facility contains customary covenants that include, among other things: limitations on the ability of the Company to incur or guarantee additional indebtedness; create liens; pay dividends on or repurchase stock; make certain types of investments; enter into transactions with affiliates; and sell assets or merge with other companies. The Credit Facility also requires compliance with certain financial covenants, including, (a) a ratio of current assets to current liabilities of at least 1.00 to 1.00, (b) a maximum ratio of total debt to EBITDA for the preceding four fiscal quarters of no more than 5.0 to 1.0 for periods ending on March 31, 2015 through June 30, 2016 and 5.5 to 1.0 for periods ending September 30, 2016 through December 31, 2016 and (c) a Senior Secured Debt-to-EBITDA ratio for periods ending March 31, 2015 through December 31, 2016 of no more than 2.5 to 1.0. The Company was not in compliance with the total debt to EBITDA and Senior Secured Debt-to-EBITDA ratios under the Credit Facility as of September 30, 2015.

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

Amounts borrowed under the Credit Facility will mature on September 30, 2018, and upon such date, any amounts outstanding under the Credit Facility are due and payable in full. Redeterminations of the borrowing base are made on a semi-annual basis, with an option to elect an additional redetermination every six months between the semi-annual redeterminations.

The annual interest cost under the Credit Facility, which is dependent upon the percentage of the borrowing base utilized, is, at the Company’s option, based on either the Alternate Base Rate (as defined under the terms of the Credit Facility) plus 0.75% to 1.75% or the London Interbank Offer Rate (LIBOR) plus 1.75% to 2.75%; provided, in no event may the interest rate exceed the maximum interest rate allowed by any current or future law.  Interest on ABR Loans is due and payable on a quarterly basis, and interest on Eurodollar Loans is due and payable, at the Company’s option, at one-, two-, three-, six- (or in some cases nine- or twelve-) month intervals. The Company also pays a commitment fee ranging from 0.375% to 0.5%, depending on the percentage of the borrowing base utilized. As of September 30, 2015, the annual interest rate on the Credit Facility was 2.70%.

A portion of the Credit Facility not in excess of $5 million will be available for the issuance of letters of credit by Wells Fargo. The Company will pay a rate per annum ranging from 1.75% to 2.75% on the face amount of each letter of credit issued and will pay a fronting fee equal to the greater of $500 and 0.125% of the face amount of each letter of credit issued. As of September 30, 2015, the Company has not obtained any letters of credit under the Credit Facility.

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

The Credit Facility allows the Company to hedge up to 60% of proved reserves for the first 24 months and 80% of projected production from proved developed producing reserves from 24 months up to 60 months later provided that in no event shall the aggregate amount of hedges exceed 100% of actual production in the current period. As of September 30, 2015, the Company had hedges covering 70% of its projected production through 2016.

NOTE 9 CONVERTIBLE NOTES

On March 24, 2014, the Company completed a private placement of $172.5 million in aggregate principal amount of Convertible Notes, and entered into an indenture (the “Indenture”) governing the Convertible Notes, with U.S. Bank National Association, as trustee (the “Trustee”). The Convertible Notes accrue interest at a rate of 2.00% per year, payable semiannually in arrears on April 1 and October 1 of each year, beginning on October 1, 2014. The Convertible Notes mature on April 1, 2019. As of September 30, 2015, the Convertible Notes are the Company’s unsecured senior obligations and are equal in right of payment to the Company’s existing and future senior indebtedness. The Convertible Notes had a total outstanding principal balance of $151.5 million and were convertible into approximately 863,248 shares of common stock.

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

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

Holders may convert their Convertible Notes at their option at any time prior to the close of business on the business day immediately preceding the maturity date of the Convertible Notes. The conversion rate for the Convertible Notes is 5.698 shares of the Company’s common stock per $1,000 principal amount of Convertible Notes (which represents a conversion price of approximately $175.60 per share of the Company’s common stock), subject to certain anti-dilution adjustments as provided in the Indenture. A holder that surrenders its Convertible Notes for conversion in connection with a Make-Whole Fundamental Change (as defined in the Indenture) that occurs before the maturity date may in certain circumstances be entitled to an increased conversion rate. If the Company undergoes a Fundamental Change (as defined in the Indenture), subject to certain conditions, the holder of the Convertible Notes will have the option to require the Company to repurchase all or any portion of its Convertible Notes for cash. The fundamental change purchase price will be 100% of the principal amount of the Convertible Notes to be purchased, plus any accrued and unpaid interest, including additional interest, if any, to, but excluding, the fundamental change purchase date. The Company may not redeem the Convertible Notes prior to their maturity, and no sinking fund is provided for the Convertible Notes.

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

The Indenture contains customary terms and covenants and events of default, including the acceleration of the maturity of the Credit Facility, which would, in turn, cause a default under the Indenture and permit the holders of the Convertible Notes to accelerate their maturity. If an Event of Default (as defined in the Indenture) occurs and is continuing, the Trustee or the holders of at least 25% in aggregate principal amount of the then-outstanding Convertible Notes may declare by written notice all the Convertible Notes to be immediately due and payable in full. The Company was in compliance with all covenants under the Indenture as of September 30, 2015; however, the Company was not in compliance with all covenants under the Credit Facility, and the lenders thereunder could declare a default, which if remained uncured, would allow the lenders under the Credit Facility to accelerate the maturity of the amounts outstanding under the Credit Facility. As of September 30, 2015, the Company had drawn approximately $160 million toward its $200 million borrowing base under the Credit Facility. The Company’s borrowing base under its Credit Facility was subject to its semi-annual redetermination on October 6, 2015, and the lenders decreased the borrowing base to $120 million. This redetermination resulted in an outstanding deficiency under the Credit Facility of approximately $19.6 million. Under the terms of the Credit Agreement, the Company is permitted to repay the deficiency in three monthly installments beginning 30 days after the date of the redetermination. The Company does not expect to be able to make the monthly installments, which will result in a default under the Credit Agreement. In accordance with the provisions under ASC 470-10-45-1, the Company has classified the balance of the Convertible Notes as a current liability as of September 30, 2015. On November 5, 2015, the Company and certain of its subsidiaries entered into a Forbearance Agreement with the lenders party to the Credit Agreement. Pursuant to the Forbearance Agreement, the Lenders agreed to forbear from exercising their rights and remedies under the Credit Agreement until December 18, 2015 with respect to certain events of defaults under the Credit Agreement. For additional information regarding the Forbearance Agreement, see Note 15 Subsequent Events— Forbearance Agreement.

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

NOTE 10  ASSET RETIREMENT OBLIGATION

The Company has asset retirement obligations associated with the future plugging and abandonment of its proved oil and natural gas properties and related facilities. Under the provisions of ASC 410-20-25, the fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred and can be reasonably estimated, and a corresponding increase in the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depleted using the units of production method. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. The fair value of additions to the asset retirement obligations is estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plugging and abandonment costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors (average of 2.5% for each of the periods presented); and (iv) a credit-adjusted risk-free interest rate (average of 7.0% for each of the periods presented). These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change. The Company has no assets that are legally restricted for purposes of settling asset retirement obligations.

The following table summarizes the Company’s asset retirement obligation transactions recorded in accordance with the provisions of ASC 410-20-25 for the nine months ended September 30, 2015 and the year ended December 31, 2014:

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

NOTE 11  INCOME TAXES

Deferred income tax assets and liabilities are determined based upon differences between the financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse. Accounting standards require the consideration of a valuation allowance for deferred tax assets if it is “more likely than not” that some component or all of the benefits of deferred tax assets will not be realized. As of September 30, 2015 and December 31, 2014, the Company maintained a full valuation allowance for all deferred tax assets. Based on these requirements no provision or benefit for income taxes has been recorded for deferred taxes. There were no recorded unrecognized tax benefits at the end of the reporting period.

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NOTE 12 FAIR VALUE

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

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

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

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

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

Fair Value on a Recurring Basis

The following schedule summarizes the valuation of financial instruments measured at fair value on a recurring basis in the condensed consolidated balance sheet as of September 30, 2015:

	Fair Value Measurements at September 30, 2015 Using
	Quoted Prices In Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Warrant Liability – Long Term Liability	$	—	$	—		$	(187,000	)
Commodity Derivatives – Current Asset (oil puts)		—		14,310,070			—
Commodity Derivatives – Non Current Asset (oil puts)		—		3,442,664			—
Commodity Derivatives – Current Liability (oil put premiums)		—		(7,974,013	)		—
Commodity Derivatives – Long Term Liability (oil put premiums)		—		(2,067,594	)		—
Total	$	—	$	7,711,127		$	(187,000	)

The following schedule summarizes the valuation of financial instruments measured at fair value on a recurring basis in the condensed consolidated balance sheet as of December 31, 2014:

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	Fair Value Measurements at December 31, 2014 Using
	Quoted Prices In Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Warrant Liability – Long Term Asset (Liability)	$	—	$	—	$	(2,199,000	)
Commodity Derivatives – Current Asset (oil swaps)		—		5,044,125		—
Total	$	—	$	5,044,125	$	(2,199,000	)

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

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

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

The fair value of the warrants upon issuance to White Deer Energy on February 19, 2013 was recorded at $8,626,000. The warrant revaluation gain was $221,000 and $216,000 for the three months ended September 30, 2015 and 2014, respectively, and $2,012,000 and $(1,751,000) for the nine months ended September 30, 2015 and 2014, respectively. The warrant revaluation gain (expense) is included in Other Income/Expense on the accompanying Condensed Consolidated Statements of Operations. See discussion of assumptions used in valuing the warrants at Note 13 – Derivative Instruments and Price Risk Management.

Nonrecurring Fair Value Measurements

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

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

The Company’s non-derivative financial instruments include cash and cash equivalents, restricted cash, accounts receivable, accounts payable, the Convertible Notes and the Credit Facility. The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximate fair value because of their immediate or short-term maturities. The book value of the Credit Facility approximates fair value because of its floating rate structure. The Company estimated the fair value of the Convertible Notes to be approximately $39.4 million at September 30, 2015 based on observed prices for the same or similar types of debt instruments. The Company has classified the valuations of the Convertible Notes and Credit Facility under Level 2 of the fair value hierarchy.

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NOTE 13 DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT

Commodity Price Risk

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

All derivative positions are carried at their fair value on the condensed consolidated balance sheet and are marked-to-market at the end of each period. The Company has a master netting agreement on each of the individual oil contracts. Therefore, both the current asset and liability and the non-current asset and liability are netted on the condensed consolidated balance sheet.

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

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

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

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

The use of derivative transactions involves the risk that the counterparties will be unable to meet the financial terms of such transactions. The Company has netting arrangements with its counterparties that provide for offsetting payables against receivables from separate derivative instruments.

Warrant Liability

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

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

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NOTE 14 COMMITMENTS AND CONTINGENCIES

Executive Compensation

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

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

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

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

Other

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

NOTE 15 SUBSEQUENT EVENTS

Joint Venture Agreement

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

Borrowing Base Redetermination

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

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Forbearance Agreement

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

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

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

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

Debt Conversion

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

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

The following discussion and analysis of our financial condition and results of operations should be read together with our financial statements appearing in this Form 10-Q.  This discussion contains forward-looking statements that involve risks and uncertainties because they are based on current expectations and relate to future events and future financial performance.  Our actual results may differ materially from those anticipated in these forward-looking statements as a result of many important factors, including those set forth in Part II, Item 1A of this Form 10-Q, in our Annual Report on Form 10-K for the year ended December 31, 2014 and in our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2015 and June 30, 2015 under the heading “Risk Factors.”

Overview

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

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

Assets and Acreage Holdings

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

Our acreage holdings are comprised of the operating areas below:

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

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

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

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

2015 Capital Development Plan

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

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Recent Developments

Amendment to the Credit Facility

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

Forbearance Agreement

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

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

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

Joint Venture Agreement

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

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

Finance Update

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

23

Productive Wells

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

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

(1)

11 gross (7.90 net) vertical wells relate to producing properties included within an acreage acquisition completed on August 2, 2013. The wells are producing from the Birdbear, Duperow and Red River formations. 10 gross (7.17 net) wells relate to producing properties included within an acquisition completed on February 13, 2014 and the wells are producing from the Bakken formation. 22 gross (19.90 net) wells relate to producing properties included within the acquisition completed on September 2, 2014 and the wells are producing from the Bakken formation. Operatorship was transferred to us upon closing of all acquisitions.

(2)

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

Results of Operations

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

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

24

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

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

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

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

Revenues

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

25

Net Gains on Commodity Derivatives

Net gains on commodity derivatives were $12,699,147 during the third quarter of 2015 compared to $11,184,716 in the third quarter of 2014. Net cash settlements received (paid) on commodity derivatives were $1,354,804 in the third quarter of 2015 compared to $(313,451) in the third quarter of 2014. On April 7, 2015, we entered into put option contracts for oil volumes produced from May 2015 through December 2016, whereby we are obligated to pay monthly premiums throughout the life of the contracts. For further details on our open put contracts, please refer to Note 13 – Derivative Instruments and Price Risk Management in the notes to the consolidated financial statements included in Part I, Item 1 of this Quarterly Report. Our derivatives are not designated for hedge accounting and are accounted for using the mark-to-market accounting method whereby gains and losses from changes in the fair value of derivative instruments are recognized immediately into earnings. Mark-to-market accounting treatment creates volatility in our revenues as unsettled gains and losses from derivatives are included in total revenues and are not included in accumulated other comprehensive income in the accompanying balance sheets.  As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our derivatives.  Future derivatives gains will be offset by lower future wellhead revenues. Conversely, future derivatives losses will be offset by higher future wellhead revenues based on the value at the settlement date. At September 30, 2015 and 2014, all of our derivative contracts were recorded at their fair value, which were net assets of $7,711,127 and $5,645,366, respectively.

Production Expenses

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

Production Taxes

Production taxes were $1,653,989 for the third quarter of 2015 compared to $3,142,998 for the third quarter of 2014. We pay production taxes based on realized oil and natural gas sales. Our average production tax rates were 9.3% for the third quarter of 2015 compared to 10.9% for the third quarter of 2014. Certain portions of our production occur in North Dakota and Montana jurisdictions that have lower initial tax rates for an established period of time or until an established threshold of production is exceeded, after which the tax rates are increased to the standard tax rate of 11.5%. The 2015 average production tax rate was lower than 2014 due to an oil extraction tax incentive in North Dakota for wells completed between February and June 2015.

General and Administrative Expense

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

Depletion Expense

Our depletion expense is driven by many factors, including certain exploration costs involved in the development of producing reserves, production levels and estimates of proved reserve quantities and future developmental costs. Depletion expense was $11,242,324 during the third quarter of 2015 compared to $9,193,566 during the third quarter of 2014. On a per-unit basis, depletion expense was $21.49 per Boe during the third quarter of 2015 compared to $26.14 per Boe during the third quarter of 2014. Our depletion expense is based on the capitalized costs related to properties having proved reserves, plus the estimated future development costs and asset retirement costs which are depleted and amortized on the unit-of-production method based on the estimated gross proved reserves determined by our petroleum engineers. This decrease in depletion expense during the third quarter of 2015 on a per unit basis was due primarily to a lower depletable base as a result of the impairment expense recognized in 2015.

26

Impairment of Oil and Natural Gas Properties

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

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

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

Standby Rig Expense

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

Other Expense, Net

Other expense, net was $2,514,067 for the third quarter of 2015 compared to $1,337,659 for the third quarter of 2014. We recognized a gain of $221,000 on the warrant liability for the third quarter of 2015 compared to a gain of $216,000 for the third quarter of 2014. Our warrant liability is accounted for using the mark-to-market accounting method whereby gains and losses from changes in the fair value of derivative instruments are recognized immediately into earnings. Interest expense was $2,735,348 for the third quarter of 2015, compared to $1,206,571 for the third quarter of 2014. The increase in interest expense primarily relates to the balance outstanding on the Credit Facility and increased amortization of debt issuance costs.

Net Loss

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

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

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

27

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

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

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

28

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

Revenues

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

Net Gains on Commodity Derivatives

Net gains on commodity derivatives were $8,148,386 during the first nine months of 2015 compared to $3,722,780 in the first nine months of 2014. Net cash settlements received (paid) on commodity derivatives were $5,481,384 received in the first nine months of 2015 compared to $(2,775,591) paid in the first nine months of 2014. We settled certain swap contracts early in January 2015, resulting in approximately $5,317,300 in cash settlements received. On April 7, 2015, we entered into put option contracts for oil volumes produced in May 2015 through December 2016, whereby we are obligated to pay monthly premiums throughout the life of the contracts. For further details on our open put contracts, please see Note 13 – Derivative Instruments and Price Risk Management in the notes to the consolidated financial statements included in Part I, Item 1 of this Quarterly Report. Our derivatives are not designated for hedge accounting and are accounted for using the mark-to-market accounting method whereby gains and losses from changes in the fair value of derivative instruments are recognized immediately into earnings.  Mark-to-market accounting treatment creates volatility in our revenues as unsettled gains and losses from derivatives are included in total revenues and are not included in accumulated other comprehensive income in the accompanying balance sheets.  As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our derivatives.  Future derivatives gains will be offset by lower future wellhead revenues. Conversely, future derivatives losses will be offset by higher future wellhead revenues based on the value at the settlement date. At September 30, 2015 and 2014, all of our derivative contracts were recorded at their fair value, which were net assets of $7,711,127 and $5,645,366, respectively.

Production Expenses

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

Production Taxes

Production taxes were $5,488,364 for the first nine months of 2015 compared to $8,632,608 for the first nine months of 2014. We pay production taxes based on realized oil and natural gas sales. Our average production tax rates were 10.1% for the first nine months of 2015 compared to 10.9% for the first nine months of 2014. Certain portions of our production occur in North Dakota and Montana jurisdictions that have lower initial tax rates for an established period of time or until an established threshold of production is exceeded, after which the tax rates are increased to the standard tax rate of 11.5%. The 2015 average production tax rate was lower than 2014 due to an oil extraction tax incentive in North Dakota for wells completed between February and June 2015.

29

General and Administrative Expense

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

Depletion Expense

Our depletion expense is driven by many factors, including certain exploration costs involved in the development of producing reserves, production levels and estimates of proved reserve quantities and future developmental costs. Depletion expense was $31,622,386 during the first nine months of 2015 compared to $24,071,676 during the first nine months of 2014. On a per-unit basis, depletion expense was $22.57 per Boe during the first nine months of 2015 compared to $26.22 per Boe during the first nine months of 2014. Our depletion expense is based on the capitalized costs related to properties having proved reserves, plus the estimated future development costs and asset retirement costs which are depleted and amortized on the unit-of-production method based on the estimated gross proved reserves determined by our petroleum engineers. This decrease in depletion expense during the first nine months of 2015 compared to the first nine months of 2014 on a per unit basis was due primarily to a lower depletable base as a result of the impairment expense recognized in 2015.

Impairment of Oil and Natural Gas Properties

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

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

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

Standby Rig Expense

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

Other Expense, Net

Other expense, net was $5,032,362 for the first nine months of 2015 compared to $4,609,075 for the first nine months of 2014. We recognized a gain of $2,012,000 on the warrant liability for the first nine months of 2015 compared to an expense of $1,751,000 for the first nine months of 2014. Our warrant liability is accounted for using the mark-to-market accounting method whereby gains and losses from changes in the fair value of derivative instruments are recognized immediately into earnings. Interest expense was $7,044,901 for the first nine months of 2015, compared to $2,515,034 for the first nine months of 2014. The increase in interest expense primarily relates to the balance outstanding on the Credit Facility and increased amortization of debt issuance costs.

30

Net Loss

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

Non-GAAP Financial Measures

Adjusted EBITDA

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

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

Liquidity and Capital Resources

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

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

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

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

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

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

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

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

Equity Offerings

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

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At-the-Market Continuous Offering Program

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

Credit Facility

On November 20, 2012, we entered into a senior secured revolving credit facility (as amended, the “Credit Facility”) with Wells Fargo Bank, N.A., as administrative agent (“Wells Fargo”), and the lenders party thereto. The Credit Facility is a senior secured reserve-based revolving credit facility with a maximum commitment of $400 million. On April 30, 2015, in connection with the semi-annual borrowing base redetermination, we and our lending group entered into an amendment to the Credit Facility. The amendment to the Credit Facility reduced the borrowing base from $250 million to $200 million. As of September 30, 2015, we had drawn approximately $160 million toward our $200 million borrowing base under the Credit Facility. Our borrowing base under the Credit Facility was subject to its semi-annual redetermination on October 6, 2015, and the lenders decreased the borrowing base to $120 million. This redetermination resulted in an outstanding deficiency under the Credit Facility of approximately $19.6 million. Under the terms of the Credit Agreement, we are permitted to repay the deficiency in three monthly installments beginning 30 days after the date of the redetermination. We do not expect to be able to make the monthly installments, which will result in a default under the Credit Agreement. The Credit Facility contains customary covenants that include, among other things: limitations on our ability to incur or guarantee additional indebtedness; create liens; pay dividends on or repurchase stock; make certain types of investments; enter into transactions with affiliates; and sell assets or merge with other companies. The Credit Facility also requires compliance with certain financial covenants, including, (a) a ratio of current assets to current liabilities of at least 1.00 to 1.00, (b) a maximum ratio of total debt to EBITDA for the preceding four fiscal quarters of no more than 5.0 to 1.0 for periods ending on March 31, 2015 through June 30, 2016 and 5.5 to 1.0 for periods ending September 30, 2016 through December 31, 2016 and (c) a Senior Secured Debt-to-EBITDA ratio for periods ending March 31, 2015 through December 31, 2016 of no more than 2.5 to 1.0. We were not in compliance with the total debt to EBITDA and Senior Secured Debt-to-EBITDA ratios under the Credit Facility as of September 30, 2015 and do not expect to be in compliance with these ratios in the near future.

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

Amounts borrowed under the Credit Facility will mature on September 30, 2018, and upon such date, any amounts outstanding under the Credit Facility are due and payable in full. Redeterminations of the borrowing base are made on a semi-annual basis, with an option to elect an additional redetermination every six months between the semi-annual redeterminations.

The annual interest cost under the Credit Facility, which is dependent upon the percentage of the borrowing base utilized, is, at our option, based on either the Alternate Base Rate (as defined under the terms of the Credit Facility) plus 0.75% to 1.75% or the London Interbank Offer Rate (LIBOR) plus 1.75% to 2.75%; provided, in no event may the interest rate exceed the maximum interest rate allowed by any current or future law.  Interest on ABR Loans is due and payable on a quarterly basis, and interest on Eurodollar Loans is due and payable, at our option, at one-, two-, three-, six- (or in some cases nine- or twelve-) month intervals. We also pay a commitment fee ranging from 0.375% to 0.5%, depending on the percentage of the borrowing base utilized. As of September 30, 2015, the annual interest rate on the Credit Facility was 2.70%.

A portion of the Credit Facility not in excess of $5 million will be available for the issuance of letters of credit by Wells Fargo. We will pay a rate per annum ranging from 1.75% to 2.75% on the face amount of each letter of credit issued and will pay a fronting fee equal to the greater of $500 and 0.125% of the face amount of each letter of credit issued. As of September 30, 2015, we have not obtained any letters of credit under the Credit Facility.

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

The Credit Facility allows us to hedge up to 60% of our proved reserves for the first 24 months and 80% of projected production from proved developed producing reserves from 24 months up to 60 months later provided that in no event shall the aggregate amount of hedges exceed 100% of actual production in the current period. As of September 30, 2015, we had hedges covering 70% of our projected production through 2016.

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Satisfaction of Our Cash Obligations for the Next Twelve Months

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

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

Our prospects must be considered in light of the risks, particularly companies in the oil and natural gas exploration industry. To address these risks we must, among other things, implement and successfully execute our business and marketing strategy, respond to competitive developments and attract, retain and motivate qualified personnel. There can be no assurance that we will be successful in addressing such risks, and the failure to do so can have a material adverse effect on our business prospects, financial condition and results of operations.

Effects of Inflation and Pricing

The oil and natural gas industry is cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry put extreme pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do all associated costs. Conversely, in a period of declining prices, associated cost declines are likely to lag and may not adjust downward in proportion. Material changes in prices also impact our current revenue stream, estimates of future reserves, borrowing base calculations under our Credit Facility, impairment assessments of oil and natural gas properties, and values of properties in purchase and sale transactions. Material changes in prices can impact our stock price and therefore our ability to raise capital, borrow money and attract and retain personnel. While we do not currently expect business costs to materially increase, higher prices for oil and natural gas could result in increases in the costs of materials, services and personnel necessary for our operations. See Part II—Other Information—Item IA. Risk Factors.

Derivative Instruments

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

Cash and Cash Equivalents

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

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Net Cash Provided By Operating Activities

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

Net Cash Used For Investment Activities

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

Net Cash Provided By Financing Activities

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

Off-Balance Sheet Arrangements

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

Critical Accounting Policies

The preparation of financial statements in accordance with generally accepted accounting principles requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. Certain of our accounting policies are considered critical, as these policies are the most important to the depiction of our financial statements and require significant, difficult or complex judgments, often employing the use of estimates about the effects of matters that are inherently uncertain. A summary of our significant accounting policies is included in Note 2—Basis of Presentation and Significant Accounting Policies to our consolidated financial statements included in our annual report on Form 10-K for the year ended December 31, 2014, as well as in the Management’s Discussion and Analysis of Financial Condition and Results of Operations section in such Form 10-K. There have been no significant changes in the application of our critical accounting policies during the nine-month period ended September 30, 2015.

Cautionary Factors That May Affect Future Results

This Quarterly Report on Form 10-Q contains, and we may from time to time otherwise make in other public filings, press releases and presentations, forward-looking statements within the meaning of the federal securities laws. All statements other than statements of historical facts are forward-looking statements.  Such statements can be identified by the use of forward-looking terminology such as “believe,” “expect,” “may,” “should,” “seek,” “on-track,” “plan,” “project,” “forecast,” “intend” or “anticipate,” or the negative thereof or comparable terminology, or by discussions of vision, strategy or outlook, including statements related to our beliefs and intentions with respect to our growth strategy, including the amount we may invest, the location and the scale of the drilling projects in which we intend to participate; our beliefs with respect to the potential value of drilling projects; our beliefs with regard to the impact of environmental and other regulations on our business; our beliefs with respect to the strengths of our business model; our assumptions, beliefs, and expectations with respect to future market conditions; our plans for future capital expenditures; and our capital needs, the adequacy of our capital resources, and potential sources of capital. You are cautioned that our business and operations are subject to a variety of risks and uncertainties, many of which are beyond our control and, consequently, our actual results may differ materially from those projected by any forward-looking statements. You should consider carefully the statements under the “Risk Factors” section of this report, in our Annual Report on Form 10-K for the year ended December 31, 2014, in our Quarterly Reports on Form 10-Q for the three months ended March 31, 2015 and June 30, 2015 and the other disclosures contained herein and therein, which describe factors that could cause our actual results to differ from those anticipated in the forward-looking statements, including, but not limited to, the following factors:

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

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

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

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

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

· our ability to retain key members of management; 

· volatility in commodity prices for oil and natural gas;

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

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

· our ability to obtain permits and government approvals;

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

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

· substantial impairment write-downs;

· our ability to replace oil and natural gas reserves;

· environmental risks;

· drilling and operating risks;

· exploration and development risks;

· effects of governmental regulation;

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

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

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

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

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

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

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

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

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

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

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

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

Based on the September 30, 2015 published commodity futures price curves for crude oil, a hypothetical price increase or decrease of $1.00 per Bbl for crude oil would increase or decrease the fair value of our net commodity derivative asset by approximately $1.5 million.

Interest Rate Risk

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

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

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ITEM 4. CONTROLS AND PROCEDURES

We maintain disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, or the “Exchange Act”) that are designed to ensure that information required to be disclosed in Exchange Act reports is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. Management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable, not absolute, assurance of achieving their objectives and management necessarily applies its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

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

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

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

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

ITEM 1A. RISK FACTORS

Our business is subject to a number of risks, some of which are beyond our control. In addition to the other information set forth in this report, you should carefully consider the factors discussed in Item 1A –“Risk Factors” of our Annual Report on Form 10-K for the fiscal year ended December 31, 2014, as filed with the SEC on March 10, 2015 and Item 1A. – “Risk Factors” of our Quarterly Reports on Form 10-Q for the three months ended March 31, 2015, as filed with the SEC on May 4, 2015, and for the three months ended June 30, 2015, as filed with the SEC on August 4, 2015, that could have a material adverse effect on our business, results of operations, financial condition and/or liquidity and that could cause our operating results to vary significantly from period to period. As of September 30, 2015, there have been no material changes to the risk factors disclosed in our most recent Annual Report on Form 10-K and our Quarterly Reports on Form 10-Q, except as stated below. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition, or operating results in the future.

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

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

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

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

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

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

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

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

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

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

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The reduction in our borrowing base in October 2015 requires us to repay the $19.6 million in excess of the borrowing base. Under the terms of the Credit Agreement, we are obligated to repay the deficiency in three monthly installments following the date of the redetermination. We do not expect to be able to make the monthly installments, which will result in a default under the Credit Agreement. We and our advisors are negotiating with the lending group regarding a repayment schedule and continue to work with a group of term debt providers for a term debt solution. We believe we will need to complete certain transactions, including management of and/or refinancing of our debt capital structure and potential asset sales, to have sufficient liquidity to satisfy all of our obligations, including eliminating the approximate $19.6 million deficiency under the Credit Facility in the near term and obligations such as oil, natural gas and produced water transportation and processing commitments, fixed drilling commitments and operating leases, in the long term. As a result, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out our business plans, which would materially and adversely impact our financial condition and results of operations and impair our ability to service our indebtedness. Additionally, our Credit Facility contains covenants limiting our ability to incur additional indebtedness and requiring us to maintain certain financial ratios, including, (a) a ratio of current assets to current liabilities of at least 1.00 to 1.00, (b) a maximum ratio of total debt to EBITDA for the preceding four fiscal quarters of no more than 5.0 to 1.0 for periods ending on March 31, 2015 through June 30, 2016 and 5.5 to 1.0 for periods ending September 30, 2016 through December 31, 2016 and (c) a Senior Secured Debt-to-EBITDA ratio for periods ending March 31, 2015 through December 31, 2016 of no more than 2.5 to 1.0. We were not in compliance with the total debt to EBITDA and Senior Secured Debt-to-EBITDA ratios under the Credit Facility as of September 30, 2015. A resultant breach of the covenants and the breach of the deficiency repayment under our Credit Facility could cause a default under the Credit Agreement if not amended by the lending group, and the lenders would be able to accelerate the maturity of the credit agreement and exercise other rights and remedies. This, in turn, would cause a default under the Convertible Notes and permit the holders of those notes to accelerate their maturity. Any violation of the terms of the Forbearance that would result in a default of the Credit Agreement and subsequent cross-default under the Convertible Notes would have an adverse effect on our operations and liquidity.

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

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

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

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

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

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

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

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

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

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

Defaults under Credit Facility

On November 20, 2012, we entered into a senior secured revolving credit facility (as amended, the “Credit Facility”) with Wells Fargo Bank, N.A., as administrative agent (“Wells Fargo”), and the lenders party thereto. The Credit Facility is a senior secured reserve-based revolving credit facility with a maximum commitment of $400 million. On April 30, 2015, in connection with the semi-annual borrowing base redetermination, we and our lending group entered into an amendment to the Credit Facility, which reduced the borrowing base from $250 million to $200 million. As of September 30, 2015, we had drawn approximately $160 million toward the $200 million borrowing base under the Credit Facility. The borrowing base under the Credit Facility was subject to a semi-annual redetermination on October 6, 2015, and the lenders decreased the borrowing base to $120 million. This redetermination resulted in an outstanding deficiency under the Credit Facility of approximately $19.6 million. Under the terms of the Credit Facility, we are permitted to repay the deficiency in three monthly installments beginning 30 days after the date of the redetermination. We do not expect to be able to make the monthly installments, which will result in a default under the Credit Facility. The Credit Facility also contains customary covenants that include, among other things: limitations on our ability to incur or guarantee additional indebtedness; create liens; pay dividends on or repurchase stock; make certain types of investments; enter into transactions with affiliates; and sell assets or merge with other companies. The Credit Facility also requires compliance with certain financial covenants, including, (a) a ratio of current assets to current liabilities of at least 1.00 to 1.00, (b) a maximum ratio of total debt to EBITDA for the preceding four fiscal quarters of no more than 5.0 to 1.0 for periods ending on March 31, 2015 through June 30, 2016 and 5.5 to 1.0 for periods ending September 30, 2016 through December 31, 2016 and (c) a Senior Secured Debt-to-EBITDA ratio for periods ending March 31, 2015 through December 31, 2016 of no more than 2.5 to 1.0. We were not in compliance with the total debt to EBITDA and Senior Secured Debt-to-EBITDA ratios under the Credit Facility as of September 30, 2015 and do not expect to be in compliance in the near term.

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

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

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

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ITEM 5. OTHER INFORMATION

Entry into New Employment Agreements

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

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

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

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

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

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

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

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

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

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

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

ITEM 6. EXHIBITS

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

101.INS* XBRL Instance Document

101.SCH* XBRL Schema Document

101.CAL* XBRL Calculation Linkbase Document

101.DEF* XBRL Definition Linkbase Document

101.LAB* XBRL Label Linkbase Document

101.PRE* XBRL Presentation Linkbase Document

 *           Attached hereto.

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SIGNATURES

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

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

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