10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2014

OR

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

For the transition period from                  to

Commission File No. 1-35097

Emerald Oil, Inc.

(Exact name of registrant as specified in its charter)

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

1600 Broadway, Suite 1360
Denver, CO	80202
(Address of principal executive offices)	(Zip Code)

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

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class	Name of Each Exchange On Which Registered
Common Stock, $0.001 par value	NYSE MKT

Securities registered pursuant to Section 12(g) of the Act:

None

(Title of Class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes ¨ No x

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 (§232.405 of this chapter) 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

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

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

The aggregate market value of the registrant’s voting and non-voting common equity held by non-affiliates of the registrant on the last business day of the registrant’s most recently completed second fiscal quarter (based on the closing sale price as reported by the NYSE MKT) was approximately $357 million.

As of March 10, 2015, the registrant had 107,904,756 shares of common stock issued and outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the proxy statement related to the registrant’s 2015 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2014, are incorporated by reference into Part III of this report.

CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

We are including the following discussion to inform our existing and potential security holders generally of some of the risks and uncertainties that can affect our company and to take advantage of the “safe harbor” protection for forward-looking statements that applicable federal securities law affords.

From time to time, our management or persons acting on our behalf may make forward-looking statements to inform existing and potential security holders about our company. All statements other than statements of historical facts included in this report are forward-looking statements. When used in this report, forward-looking statements are generally accompanied by terms or phrases such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “target,” “plan,” “intend,” “seek,” “goal,” “will,” “should,” “may” or other words and similar expressions that convey the uncertainty of future events or outcomes. Items contemplating or making assumptions about our vision, strategy, or outlook, including statements related to our beliefs and intentions with respect to our growth strategy, including our expectations regarding our operational, exploration and development plans; our expectations regarding the nature and amount of our reserves, our production, cash flows and recoveries; 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 also constitute such forward-looking statements.

Forward-looking statements involve inherent risks and uncertainties, and important factors (many of which are beyond our control) that could cause actual results to differ materially from those set forth in the forward-looking statements, including, but not limited to, the following:

· volatility in commodity prices for oil and natural gas;

· 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;

· 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;

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

· our ability to retain key members of management;

· our ability to replace oil and natural gas reserves;

· drilling and operating risks;

· exploration and development risks;

· 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;

· ability to obtain permits and government approvals;

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

· interest payment requirements of our debt obligations;

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

· substantial impairment write-downs;

· environmental risks;

· effects of governmental regulation;

· 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;

· 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; and

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

We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. Accordingly, results actually achieved may differ materially from expected results in these statements. Forward-looking statements speak only as of the date they are made. You should consider carefully the statements in Item 1A. Risk Factors and other sections of this report, which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements. We do not undertake, and specifically disclaim, any obligation to update any forward-looking statements to reflect events or circumstances occurring after the date of such statements.

Readers are urged not to place undue reliance on these forward-looking statements, which speak only as of the date of this report. We assume no obligation to update any forward-looking statements in order to reflect any event or circumstance that may arise after the date of this report, other than as may be required by applicable law or regulation. Readers are urged to carefully review and consider the various disclosures made by us in our reports filed with the United States Securities and Exchange Commission (the “SEC”) that attempt to advise interested parties of the risks and factors that may affect our business, financial condition, results of operations and cash flows. If one or more of these risks or uncertainties materialize, or if the underlying assumptions prove incorrect, our actual results may vary materially from those expected or projected.

GLOSSARY OF OIL AND NATURAL GAS TERMS

The definitions set forth below apply to the indicated terms as used in this report. All volumes of natural gas referred to herein are stated at the legal pressure base of the state or area where the reserves exist and at 60 degrees Fahrenheit and in most instances are rounded to the nearest major multiple.

3-D seismic.   The method by which a three dimensional image of the earth’s subsurface is created through the interpretation of reflection seismic data collected over a surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do conventional surveys and contribute significantly to field appraisal, exploitation and production.

Bbl.   One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to oil or other liquid hydrocarbons.

Boe.   Barrels of oil equivalent in which six Mcf of natural gas equals one Bbl of oil.

Boe/d.   Boe per day.

BTU or British thermal unit.   The quantity of heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

Completion.   The installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.

Development well.   A well drilled within the proved areas of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Drilling spacing unit (DSU). The area designated in a spacing order as a unit and within which all operators have the opportunity to participate in the well or wells drilled thereon on a just and equitable basis.

Dry hole or well.   A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Estimated ultimate recoveries or EURs. Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

Exploratory well.   A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

Field.   An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Gross acres or gross wells.   The total acres or wells, as the case may be, in which a working interest is owned.

Held by production.   A provision in an oil and gas lease that extends a company’s right to operate a lease as long as the property produces a minimum quantity of oil and natural gas.

Hydraulic fracturing (or fracking). The technique of improving a well’s production or injection rates by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this technique, sand or other material may also be injected into the formation to keep the channel open, so that fluids or natural gases may more easily flow through the formation.

Mbbls. Thousand stock tank barrels, or 42,000 U.S. gallons liquid volume, of oil or other liquid hydrocarbons.

Mboe Thousand barrels of oil equivalent.

Mcf.   One thousand cubic feet of natural gas.

Net acres or net wells.   The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.

NYMEX.   The New York Mercantile Exchange, which is a designated contract market that facilitates and regulates the trading of oil and natural gas contracts subject to NYMEX rules and regulations.

Operator.   The individual or company responsible for the exploration, exploitation and production of an oil or natural gas well or lease.

PV10.   The estimated future net revenue, discounted at a rate of 10% per annum, before income taxes and with no price or cost escalation or de-escalation in accordance with guidelines promulgated by the SEC.

Pad. A temporary drilling location generally consisting of 4 to 5 acres that are cleared, leveled and surfaced over for siting a drilling rig, trucks and various other equipment required for drilling and completion activities.

Prospect. A specific geographic area which, based on supporting geological, geophysical ro other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Productive well.   A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Proved developed producing reserves (PDP).   Proved developed reserves that are expected to be recovered from completion intervals currently open in existing wells and capable of production.

Proved developed non-producing reserves (PDNP).   Proved oil and natural gas reserves that are developed behind pipe, shut-in or that can be recovered through improved recovery only after the necessary equipment has been installed, or when the costs to do so are relatively minor. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not started producing, (2) wells that were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe reserves are expected to be recovered from zones in existing wells that will require additional completion work or future recompletion prior to the start of production.

Proved developed reserves.   Proved reserves that are expected to be recovered from existing wellbores, whether or not currently producing, without drilling additional wells. Production of such reserves may require a recompletion.

Proved reserves.   Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for estimation.

Proved undeveloped reserves (PUD).   Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Reservoir.   A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Spud.   Start (or restart) drilling a new well.

Standardized measure.   The estimated future net revenue, discounted at a rate of 10% per annum, after income taxes and with no price or cost escalation, calculated in accordance with Accounting Standards Codification (“ASC”) 932.

Undeveloped acreage.   Leasehold acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

Working interest.   An interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.

EMERALD OIL, INC.

TABLE OF CONTENTS

		Page
	Part I
Item 1.	Business	1
Item 1A.	Risk Factors	17
Item 1B.	Unresolved Staff Comments	32
Item 2.	Properties	32
Item 3.	Legal Proceedings	32
Item 4.	Mine Safety Disclosures	32
	Part II
Item 5.	Market For Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities	32
Item 6.	Selected Financial Data	36
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	37
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	52
Item 8.	Financial Statements and Supplementary Data	53
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	53
Item 9A.	Controls and Procedures	53
Item 9B.	Other Information	56
	Part III
Item 10.	Directors, Executive Officers and Corporate Governance	56
Item 11.	Executive Compensation	56
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters	56
Item 13.	Certain Relationships and Related Transactions, and Director Independence	56
Item 14.	Principal Accountant Fees and Services	56
	Part IV
Item 15.	Exhibits and Financial Statement Schedules	56
Signatures		62
Index to Financial Statements		F-1

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EMERALD OIL, INC.
  
ANNUAL REPORT ON FORM 10-K
  
FOR FISCAL YEAR ENDED DECEMBER 31, 2014
  
PART I

Item 1.   Business

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.

The following table summarizes our estimated proved reserves by category as of December 31, 2014, their corresponding pre-tax PV-10 values and our total standardized measure of discounted future net cash flows as of December 31, 2014:

	Oil (MBbls)		Gas (MMcf)		Total (MBoe) (1)		Pre-Tax PV-10 (2) (in thousands)
Proved Developed Producing
Bakken/Three Forks – operated		9,602.8		7,977.1		10,932.3	$	320,100.5
Bakken/Three Forks – non-operated		850.0		793.7		982.2		30,925.3
Other fields/acquired properties		2,432.5		2,635.4		2,871.8		56,831.8
Total Proved Developed		12,885.3		11,406.2		14,786.3		407,857.6
Proved Developed, Not Producing
Bakken/Three Forks – operated		308.8		264.3		352.9		10,146.9
Total Proved Developed, Not Producing		308.8		264.3		352.9		10,146.9
Total Proved Developed Properties		13,194.1		11,670.5		15,139.2		418,004.5
Proved Undeveloped
Bakken/Three Forks – operated		9,478.6		9,221.2		11,015.5		115,419.2
Bakken/Three Forks – non-operated		153.5		178.2		183.2		1,662.9
Total Proved Undeveloped		9,632.1		9,399.4		11,198.7		117,082.1
Total Proved Reserves		22,826.2		21,069.9		26,337.9		535,086.6
Discounted Future Income Taxes								(90,771.2	)
Standardized Measure of Discounted Future Net Cash Flows							$	444,315.4

(1) Barrels of oil equivalent (Boe) are computed based on a conversion ratio of one Boe for each barrel of oil and one Boe for every 6,000 cubic feet (i.e., 6 Mcf) of natural gas.

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(2) The pre-tax present value of future net cash flows, or PV-10, is a non-GAAP measure because it excludes income tax effects. Management believes that pre-tax cash flow amounts are useful for evaluative purposes since future income taxes, which are affected by a company’s unique tax position and strategies, can make after-tax amounts less comparable. We derive PV-10 based on the present value of estimated future revenues to be generated from the production of proved reserves, net of estimated production and future development costs and future plugging and abandonment costs, using the twelve-month arithmetic average of the first of the month prices without giving effect to hedging activities or future escalation, costs as of the date of estimate without future escalation, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion, amortization and impairment and income taxes, and discounted using an annual discount rate of 10%.

Since 2012, we have significantly increased our annual average daily oil and natural gas sales volumes from 936 Boe/d for the year ended December 31, 2012 to 3,549 Boe/d for the year ended December 31, 2014, as summarized in the following table.

	Year Ended December 31,
	2014		2013		2012
Sales Volume (Total)
Oil (Bbls)		1,238,807		580,797		320,147
Natural Gas (Mcf)		338,536		211,608		129,648
Sales volumes (Boe)		1,295,230		616,065		341,755
Average Daily Sales
Oil (Bbls)		3,394		1,591		877
Natural Gas (Mcf)		927		580		355
Sales volumes (Boe)		3,549		1,688		936
Average Sales Prices
Oil, Net of Settled Derivatives (Bbls)	$	84.01	$	87.16	$	85.05
Natural Gas (Mcf)		7.79		6.48		6.68
Barrel of Oil Equivalent with Settled Derivatives (Boe)	$	82.39	$	84.40	$	82.21
Average Production Costs
Oil (Bbls)	$	16.16	$	14.38	$	8.26
Natural Gas (Mcf)		1.58		0.81		0.65
Barrel of Oil Equivalent (Boe)	$	15.87	$	13.83	$	7.98

In 2014, we incurred total capital well costs of approximately $298.6 million. Our well expenditures in 2014 related to our operated wells totaled $276.2 million to drill 28.6 net wells and complete 24.2 net wells, compared to our budgeted operated well expenditures of $250.0 million. Our expenditures related to non-operated wells were $22.4 million during the year to drill 3.8 net wells and complete 4.4 net wells. We exceeded our capital budget by $48.6 million because we drilled more net wells compared to our original operated development budget, the timing of well completions was faster than projected and the completion costs were higher than expected. We deployed more capital into our non-operated properties due to attractive non-operated well economics through the first three quarters of 2014. Our oil, natural gas and natural gas liquid sales in 2014 were $101.2 million on 1,295 MBoe in 2014, compared to $54.0 million on 616 MBoe in 2013, a volumetric increase of 110%.

In December 2014, management decided to reduce the 2015 development program because of the fallen commodity price environment. We released two of our three operated rigs in December 2014. Our 2015 production and capital expenditure estimates are currently based upon a variable one-rig drilling program. We plan to drill and complete five wells over the next twelve months, four of which are expected to be spud before the end of the second quarter of 2015, and the fifth well expected to be spud in the second half of 2015. We have a backlog of permits in hand, and may add additional wells to the 2015 development schedule if commodity prices improve. The one rig will be held on standby during 2015 while it is not drilling. In our Low Rider operated area in McKenzie County, North Dakota, we have a current inventory of nine wells remaining to be completed over the remainder of 2015.

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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. We expect to fund our 2015 capital program through existing cash on hand, our expected cash flows from operations, proceeds from the equity offering completed in February 2015 and borrowing capacity expected to be available under our revolving credit facility.

As of December 31, 2014, we had approximately 122,000 net acres in the Williston Basin. We operate approximately 98,000 net acres, or 80% of our total net acreage. We have identified approximately 890 net potential drilling locations on this acreage prospective for oil in the Bakken, Three Forks and Pronghorn Sand formations, based on industry accepted well down-spacing assumptions. Consistent with such assumptions, we believe that each 1,280-acre drilling spacing unit can support up to approximately four Bakken and three Three Forks well locations. We believe our acreage prospective for Pronghorn Sand can support four horizontal well locations.

Our acreage holdings are comprised of the operating areas below:

· 72,000 net acres in the Low Rider area of McKenzie County, North Dakota;

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

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

· 36,000 net acres in the Lewis & Clark area of McKenzie County, North Dakota south of the Low Rider area.

Strategy

Our goal is to increase stockholder value by growing production, cash flows, estimated proved reserves, and our leasehold position to generate attractive rates of return on capital. Key elements of our business strategy include:

Focus on Developing Our Williston Basin Leasehold Position.  We intend to continue developing our acreage position in the Williston Basin in order to maximize the value of our resource potential. Due to the results from our operated producing wells to date and current commodity prices, we intend to concentrate substantially all of our planned 2015 capital expenditures in the Williston Basin. As a result of the recent decrease in commodity prices, we intend to operate a variable one-rig drilling program during 2015, which rig will be held on standby while it is not drilling. We believe that our experience in the application of advanced drilling and completion techniques along with modern fracture stimulation design provide us with a competitive advantage in developing our approximate 122,000 net acres prospective in the Bakken, Three Forks and Pronghorn Sand formations.

Retain Operational Control.  In our principal development targets, we seek to maintain operational control of our development and drilling activities. As operator of approximately 80% of our net acreage, we retain more control over the timing, selection and process of drilling prospects and completion design, which enhances our ability to maximize our return on invested capital and gives us greater control over the timing, allocation and amounts of our capital expenditures. Retaining operational control also gives us the ability to control the financing, construction and operation of infrastructure related to our production operations.

Adopt and Employ Leading Drilling and Completion Techniques.  Our management team is focused on enhancing our drilling and completion techniques to maximize overall well economics. We continuously evaluate our internal drilling and completion results and monitor the results of other operators to improve our operating practices. We believe this continued evolution will continue to enhance our initial production rates, ultimate recovery factors and rates of return on invested capital.

Evaluate and Pursue Strategic Acquisitions in the Williston Basin.  We intend to continue to evaluate both asset and corporate acquisition opportunities and remain focused on acquiring additional acreage and producing assets in the Williston Basin in areas near our core acreage. By focusing on the Williston Basin, we intend to maximize the efficiency of our drilling and exploration activities, and further leverage our knowledge and experience. Such focus provides us with the opportunity to capture economies of scale, including the ability to drill multiple wells from a single drilling pad, thereby reducing the time and cost of rig mobilization.

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Maintain Financial Liquidity and Capacity to Capitalize on Growth Opportunities.  We are committed to maintaining a conservative financial strategy by managing our liquidity position and leverage levels. As of December 31, 2014, we had $75.0 million in outstanding borrowings under our revolving credit facility. As of December 31, 2014, we had approximately $187.0 million of liquidity available, including approximately $12.4 million in unrestricted cash and short-term investments and $175.0 million available under our revolving credit facility. While we expect the borrowing capacity available under our revolving credit facility to be reduced if commodity prices do not improve, we expect that our liquidity position, including borrowing capacity expected under our revolving credit facility, along with internally generated cash flows, will provide financial flexibility as we continue to develop our acreage position in the Williston Basin.

Competitive Strengths

We believe we possess a range of competitive strengths, including:

Substantial Leasehold Position with Multi-Year Inventory of Identified Drilling Locations in the Williston Basin, Targeting the Bakken, Three Forks and Pronghorn Sand Formations. We have assembled approximately 122,000 net acres in the oil-producing core of the Williston Basin. We have identified an inventory of approximately 890 net potential drilling locations across our acreage position. We expect that the scale and concentration of our acreage will enable us to lower our drilling and completion costs and leverage operational efficiencies.

Oil-Weighted Production and Reserves. As of December 31, 2014, approximately 86% of our 26.3 MMBoe net proved reserves were comprised of oil, with a vast majority of all of our natural gas reserves coming from associated natural gas.

High Degree of Operational Control. We are the operator of approximately 80% of our Williston Basin acreage. This operating control allows us to better execute on our strategies of enhancing returns through operational and cost efficiencies and increasing ultimate hydrocarbon recovery by seeking to continually improve our drilling techniques, completion methodologies and reservoir evaluation processes. Additionally, as the operator of a significant majority of our acreage, we retain the ability to adjust our capital expenditure program based on commodity price outlooks. This operating control also enables us to obtain data needed for efficient exploration of horizontal prospects.

Experienced Management Team with Proven Operational, Technical and Financial Expertise. Our management team has extensive expertise in all areas of the oil and gas industry. Our operational and technical teams have an average of more than 20 years of industry experience in multiple North American resource plays. We believe our management and technical team is one of our principal competitive strengths due to our team’s proven track record in the identification, acquisition and execution of resource conversion opportunities. In addition, our technical team possesses substantial expertise in horizontal drilling techniques and acquiring and managing large development programs in multiple unconventional shale plays in North America and specifically in the Williston Basin.

Area of Operation

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.

Based on recent drilling results, along with internal and third party reserve engineering analysis, we expect wells in this area to have economic ultimate recoveries (“EURs”) that range from approximately 450 to over 600 MBoe.

Important aspects of our drilling program in this core Williston Basin area include the following:

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Long Laterals. We believe that 10,000-foot laterals provide the highest internal rate of return in our core operating areas. Although utilizing long laterals results in higher well costs, we estimate that the additional costs of drilling the long lateral and adding more fracture stimulation stages is offset by the associated incremental increase in oil production and recoverable reserves.

Multi-Well Pads. We have drilled on multi-well pads, which we believe will ultimately allow for up to seven wells per designated spacing unit. There are many advantages to multi-well pad drilling, such as reduced costs of mobilization and demobilization of our drilling rigs as a result of fewer moves, and the reduced number of drilling pads minimizes the impact on the surface locations. Furthermore, we have seen efficiencies in our completion work as we eliminate mobilization and demobilization time for our pressure pumping contractor and have the ability to simultaneously complete multiple wells using efficient fracturing techniques.

Multiple Productive Formations. Our wells in the Middle Bakken have been completed in the middle interval, while our wells in the Three Forks have been completed in the upper interval. There are multiple productive intervals in both the Bakken and Three Forks formations from which we have not yet produced. Due to the entire thickness of the multiple intervals, we believe that drilling additional wells is required within the Bakken and Three Forks formations to effectively drain the reservoir.

Contiguous Acreage. Our leasehold is largely contiguous and by virtue of our high working interest and operatorship, we can control the development pace and location of surface facilities. We believe this strategy, combined with multi-well pad drilling and long laterals, will maximize the efficiency of our drilling program and the infrastructure required to connect our wells to sales pipelines.

Infrastructure. Most of our core Williston Basin area is served by third party oil and gas gathering systems. The majority of our wells are in the process of being connected to oil and gas pipelines. Moving oil and gas through pipelines eliminates trucking costs and associated surface disturbance, and mitigates weather related production interruptions. A significant portion of the oil currently produced in the Williston Basin is being transported to refineries through the utilization of railroad facilities. In other cases pipelines deliver the oil from the wellhead to the rail facilities, however in some situations trucking of the oil is still utilized.

We continue to make improvements in the volumes of natural gas delivered for sale. As the capacity of natural gas pipelines and related processing facilities continues to increase, we expect to be able to capture additional revenue generated from the sale of associated natural gas and eliminate any significant flaring of gas.

Reserves

As of December 31, 2014, we had total proved reserves of approximately 26.3 MMBoe, all of which were located in the Williston Basin. Based on our December 31, 2014 reserve report, our proved reserves increased approximately 99% during 2014 primarily as a result of increased drilling activity in our operated well program and acquisitions. We incurred approximately $298.6 million of capital expenditures for drilling activities and $175.3 million for acquisitions during the year ended December 31, 2014, which directly contributed to the increase in our proved developed reserves. No other expenditures materially contributed to the development of proved developed reserves in 2014.

Our proved undeveloped reserves increased by approximately 73% during 2014 primarily as a result of increased drilling activity in our operated well program. Based on our independent reservoir engineering firm’s calculations of proved undeveloped reserves as of December 31, 2013 and 2014, approximately 2.5 MMBoe, or 38%, of proved undeveloped reserves were converted to proved developed reserves during 2014. The capital costs to develop these reserves were approximately $57.6 million. Also during 2014, we drilled wells at 46 locations and acquired 64 producing locations that did not include proved reserves as of December 31, 2013. During 2014, we added 30 new proved undeveloped locations, which resulted in the addition of approximately 6.9 MMBoe of proved undeveloped reserves. We expect to continue to convert our proved undeveloped reserves to proved developed producing reserves as additional wells are drilled and completed. At December 31, 2014, our projected costs to develop our proved undeveloped reserves were $226.2 million in 2015, 2016 and 2017. All locations comprising our proved undeveloped reserves are forecast to be drilled within five years from initially being recorded in accordance with our adopted development plan. We do not have any material amounts of proved undeveloped reserves that have remained undeveloped for five years or more from the time such reserves were initially categorized as proved undeveloped.

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Summary of Proved Oil and Natural Gas Reserves

	As of December 31,
	2014 (2)		2013 (3)
Proved Developed Oil Reserves (MBbls)		13,194.1		5,811.0
Proved Undeveloped Oil Reserves (MBbls)		9,632.1		5,764.6
Total Proved Oil Reserves (MBbls)		22,826.2		11,575.6
Proved Developed Natural Gas Reserves (MMcf)		11,670.5		5,770.6
Proved Undeveloped Natural Gas Reserves (MMcf)		9,399.4		4,231.6
Total Proved Natural Gas Reserves (MMcf)		21,069.9		10,002.2
Total Proved Oil Equivalents (MBoe) (1)		26,337.9		13,242.8
Present Value of Estimated Future Net Revenues After Income Taxes, Discounted at 10% (4) (In thousands)	$	444,315.4	$	198,371.5

(1) Barrels of oil equivalent (Boe) are computed based on a conversion ratio of one Boe for each barrel of oil and one Boe for every 6,000 cubic feet (i.e., 6 Mcf) of natural gas.

(2) The values for the 2014 oil and natural gas reserves are based on the 12-month unweighted average first of the month price January through December 31, 2014 crude oil price of $91.48 per Bbl (West Texas Intermediate price (“WTI”)) and natural gas price of $4.35 per MMBtu (Questar Rocky Mountains price). All prices were further adjusted for transportation, quality and basis differentials. The average resulting price used as of December 31, 2014 was $81.68 per Bbl of oil and $7.66 per Mcf for natural gas.

(3) The values for the 2013 oil and natural gas reserves are based on the 12-month unweighted average first of the month price January through December 31, 2013 crude oil price of $93.42 per Bbl (West Texas Intermediate price (“WTI”)) and natural gas price of $3.67 per MMBtu (Questar Rocky Mountains price). All prices were further adjusted for transportation, quality and basis differentials. The average resulting price used as of December 31, 2013 was $88.80 per Bbl of oil and $6.17 per Mcf for natural gas.

(4) The Present Value of Estimated Future Net Revenues After Income Taxes, Discounted at 10%, is referred to as the “Standardized Measure.” Please refer to the Standardized Measure Reconciliation section below.

Standardized Measure Reconciliation

The pre-tax present value of future net cash flows, or PV-10, is a non-GAAP measure because it excludes income tax effects. Management believes that pre-tax cash flow amounts are useful for evaluative purposes since future income taxes, which are affected by a company’s unique tax position and strategies, may make after-tax amounts less comparable. We derive PV-10 based on the present value of estimated future revenues to be generated from the production of proved reserves, net of estimated production and future development costs and future plugging and abandonment costs, using the 12-month arithmetic average of the first of the month prices without giving effect to hedging activities, costs as of the date of estimate without future escalation, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion, amortization, impairment and income taxes, and discounted using an annual discount rate of 10%. For more information, please refer to Supplemental Oil and Natural Gas Information (Unaudited) under Item 8 in this Annual Report. The following table reconciles the standardized measure of future net cash flows to PV-10 as of the dates shown (in thousands):

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	For the Years Ended December 31,
	2014		2013		2012
Pre-tax present value of estimated future net revenues (Pre-tax PV-10)	$	535,086.6	$	237,422.2	$	87,819.4
Present value of future income tax discounted at 10%		90,771.2		39,050.7		2,534.6
Standardized measure of discounted future net cash flows	$	444,315.4	$	198,371.5	$	85,284.8

Uncertainties are inherent in estimating quantities of proved reserves, including many risk factors beyond our control. Reserve engineering is a subjective process of estimating subsurface accumulations of oil and natural gas that cannot be measured in an exact manner. As a result, estimates of proved reserves may vary depending upon the engineer valuing the reserves. Further, our actual realized price for our oil and natural gas is not likely to average the pricing parameters used to calculate our proved reserves. As such, the oil and natural gas quantities and the value of those commodities ultimately recovered from our properties will vary from reserve estimates.

Controls Over Reserve Report Preparation, Technical Qualifications and Technologies Used

We have developed internal policies for estimating and evaluating reserves. The policies we have developed are comprehensive in nature and applied company-wide. Our internal controls over reserve estimates include reconciliation and review controls, including an independent internal review of assumptions used in the estimation by our operations personnel, and an evaluation of our reserves by an independent reservoir engineering firm. Our year-end reserve report was prepared by Netherland, Sewell & Associates, Inc. (“NSAI”) based upon a review of property interests being appraised, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, geoscience and engineering data, and other information we provided to them. To ensure accuracy and completeness of the data prior to submission to NSAI, the information we provide is reviewed by the following persons with the following qualifications:

• Vice President of Reservoir Engineering, Keith Engler: Mr. Engler has over 20 years of experience in the oil and natural gas industry in both technical and management positions. Prior to joining Emerald in 2014, Mr. Engler served as Manager of Engler Petroleum Consulting, LLC providing engineering consulting services and President of Elk Creek Energy, LLC investing in oil and natural gas projects from 2004 through 2014. From 2005 through 2009, he served as Vice President of Business Development for Savant Resources, LLC, a private oil and gas company that focused on developing unconventional resource plays, including the Bakken formation of North Dakota and Montana. Mr. Engler served in a variety of roles at EnCana Corporation from 2000 to 2004 including leading development teams for the Jonah Field and Barnett Shale assets. Mr. Engler holds a Bachelor of Science degree in Petroleum Engineering from the Colorado School of Mines. He is a registered professional engineer in Colorado and Wyoming and has previously served as the Chairman of the Denver Section of the Society of Petroleum Evaluation Engineers.

• Vice President of Exploration and Business Development, Karl Osterbuhr: Mr. Osterbuhr has over 20 years of experience in the oil and natural gas industry including experience in all types of field operations. He has expertise in geo steering horizontal wells, under balanced drilling in high temperature high pressure environments and managed pressure drilling operations. Mr. Osterbuhr's exploration experience includes over 17 separate petroleum plays in the U.S. and Canada. His technical expertise includes working with hydrothermal dolomites and other complex carbonate depositional systems, tight gas multi-storied cretaceous sandstones, multi-pay clastic and evaporate sequences as well and unconventional oil and gas shale. Prior to joining us in early 2012, Mr. Osterbuhr was self-employed as a geological consultant from 2010 to 2012. Mr. Osterbuhr founded NYSG, LLC in June 2008 with two other private equity partners and assembled 35,000 acres in the unconventional Utica Shale play in New York. Before founding NYSG, LLC, Mr. Osterbuhr served as Exploration Manager at Delta Petroleum beginning in 2007 where he was responsible for frontier exploration ventures in the Rocky Mountain basins and the onshore Gulf Coast region. Mr. Osterbuhr earned his Bachelor of Science in Geology from Kansas State University and is an active member of the American Association of Petroleum Geologists and the Society of Petroleum Engineers.

Our reserves estimates have been independently prepared by NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical person primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein is Mr. Joseph J. Spellman.

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Mr. Spellman has been practicing consulting petroleum engineering at NSAI since 1989. Mr. Spellman is a Licensed Professional Engineer in the State of Texas (No. 73709) and has over 30 years of practical experience in petroleum engineering. He graduated from University of Wisconsin-Platteville in 1980 with a Bachelor of Science Degree in Civil Engineering.

All technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; all are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

A variety of methodologies are used to determine our proved reserve estimates. The reserves set forth in the NSAI reserves report for the properties are estimated by performance methods or analogy. In general, reserves attributable to producing wells and/or reservoirs are estimated by performance methods such as decline curve analysis which utilizes extrapolations of historical production data. Reserves attributable to non-producing and undeveloped reserves included in our report are estimated by analogy.

In accordance with applicable SEC requirements, estimates of our net proved reserves and future net revenues are made using average prices at the beginning of each month in the 12-month period prior to the date of such reserve estimates and are held constant throughout the life of the properties (except to the extent a contract specifically provides for escalation).

To estimate economically recoverable oil and natural gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under Rules 210.4-10(a)(22)(v) and (26) of Regulation S-X, proved reserves must be demonstrated to be economically producible based on existing economic conditions including the prices and costs at which those reserves can be economically produced from a reservoir, determined as of the effective date of the report. With respect to the property interests we own, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, production taxes, recompletion and development costs and product prices are based on the SEC regulations, geological maps, well logs, core analyses, and pressure measurements.

The reserve data set forth in the NSAI reserves report represent only estimates, and should not be construed as being exact quantities. The estimates of reserves may or may not be actually recovered, and if recovered, the actual revenues and costs could be more or less than the estimated amounts. Moreover, estimates of reserves may increase or decrease as a result of future operations.

Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. There are numerous uncertainties inherent in estimating oil and natural gas reserves and their estimated values, including many factors beyond our control. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geologic interpretation and judgment. As a result, estimates of different engineers, including those used by us, may vary. In addition, estimates of reserves are subject to revision based upon actual production, results of future development and exploration activities, prevailing oil and natural gas prices, operating costs and other factors. The revisions may be material. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered and are highly dependent upon the accuracy of the assumptions upon which they are based. Our estimated net proved reserves, included in our SEC filings, have not been filed with or included in reports to any other federal agency. See Item 1A. Risk Factors — Estimates of proved oil and natural gas reserves are uncertain and any material inaccuracies in these reserve estimates will materially affect the quantities and the value of our reserves.

Additional discussion of our proved reserves is set forth under the heading Supplemental Oil and Natural Gas Information (Unaudited) following our audited financial statements for the years ended December 31, 2014, 2013 and 2012 in Item 8. Financial Statements and Supplementary Data in this Annual Report.

Productive Wells

The following table summarizes gross and net productive oil wells at December 31, 2014, 2013 and 2012. We had no wells targeting natural gas reservoirs as of December 31, 2014, 2013 and 2012. A net well represents our fractional working ownership interest of a gross well. The following table does not include wells that were in the process of being drilled, awaiting completion, in the process of completion or awaiting flow back subsequent to fracture stimulation.

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	December 31,
	2014				2013				2012
	Gross		Net		Gross		Net		Gross		Net
North Dakota Bakken and Three Forks – operated		46		34.77		15		10.58		—		—
North Dakota acquired production – operated (1)		43		34.98		11		7.58		—		—
North Dakota Bakken and Three Forks – non-operated		44		5.44		11		1.07		178		7.12
Montana Bakken and Three Forks – non-operated		—		—		—		—		27		2.55
Total		133		75.19		37		19.23		205		9.67

(1) 11 gross (7.91 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 (19.9 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.  

Drilling and Completion Activity

The following table summarizes our drilling activity for the years ended December 31, 2014, 2013 and 2012. Gross wells reflect the sum of all productive and dry wells, operated and non-operated, in which we own an interest, excluding producing properties acquired during the period. Net wells reflect the sum of our working interests in gross wells, excluding properties acquired during the period. The gross and net wells represent wells completed during the periods presented, regardless of when drilling was initiated.

	Year ended December 31,
	2014				2013				2012
	Gross		Net		Gross		Net		Gross		Net
Development wells:
Oil		35		22.2		7		4.6		10		0.6
Gas		—		—		—		—		—		—
Dry		—		—		—		—		—		—
Total development wells		35		22.2		7		4.6		10		0.6
Exploratory wells:
Oil		6		5.1		11		6.2		113		6.1
Gas		—		—		—		—		—		—
Dry		—		—		—		—		—		—
Total exploratory wells		6		5.1		11		6.2		113		6.1
Total wells		41		27.3		18		10.8		123		6.7

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The following table summarizes wells that were in the process of being drilled, awaiting completion, in the process of completion or awaiting flow back subsequent to fracture stimulation by state at December 31, 2014, 2013 and 2012.

	December 31,
	2014				2013				2012
	Gross		Net		Gross		Net		Gross		Net
North Dakota Bakken and Three Forks – operated		11		9.52		6		5.12		2		1.02
North Dakota acquired production – operated		—		—		—		—		—		—
North Dakota Bakken and Three Forks – non-operated		5		0.02		1		0.63		25		0.86
Montana Bakken and Three Forks – non-operated		—		—		—		—		1		0.09
Total		16		9.54		7		5.75		28		1.97

We had no dry holes in development or exploratory wells that we owned a material working interest for the years ended December 31, 2014, 2013 and 2012.

Leasehold

As of December 31, 2014, we owned an interest in approximately 122,000 net acres (171,000 gross acres) in the Williston Basin of North Dakota and Montana. Our Williston Basin leasehold position is held under fee, state and federal leases. These leases typically carry primary terms ranging from three to ten years with landowner royalties of approximately 12.5% to 22.0%. In most cases, we obtain “paid-up” fee leases, which do not require annual delay rentals. The federal lands require annual delay rentals of $1.50 to $2.00 per net acre.

The following table sets forth our gross and net acres of developed and undeveloped oil and natural gas leases as of December 31, 2014:

	Undeveloped Acreage (1)				Developed (2)				Total Acreage
	Gross		Net		Gross		Net		Gross		Net
North Dakota		108,189		88,813		43,951		25,397		152,140		114,210
Montana		16,074		6,159		2,878		1,862		18,952		8,021
Total		124,263		94,972		46,829		27,259		171,092		122,231

(1) Undeveloped acreage is lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage includes proved reserves.

(2) Developed acreage is the number of acres that are allocated or assignable to producing wells or wells capable of production.

At 2014 year end, approximately 22% of our total acreage was developed. In addition, approximately 51% of our total acreage position was either developed or held by production as of December 31, 2014.

We believe we have satisfactory title, in all material respects, to substantially all of our producing properties in accordance with standards generally accepted in the oil and natural gas industry. Substantially all of our proved oil and natural gas properties are pledged as collateral for borrowings under our revolving credit facility.

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Undeveloped Acreage

We do not own any physical real estate, but, instead, our acreage is comprised of leasehold interests subject to the terms and provisions of lease agreements that provide us the right to drill and maintain wells in specific geographic areas. All lease arrangements that comprise our acreage positions are established using standard terms used in the oil and natural gas industry for many years.

In general, our lease agreements stipulate three- to ten-year primary terms. Bonuses and royalty rates are negotiated on a case-by-case basis consistent with industry standard pricing. Once a well is drilled and production established, the unit is considered held by production, meaning the lease continues as long as hydrocarbons are being produced. Other locations within the drilling unit created for a well may also be drilled at any time as long as the lease is held by production.

Substantially all of the leases summarized in the preceding table will expire at the end of their respective primary terms unless (i) we have obtained production from the acreage subject to the lease prior to the end of the primary term, in which event the lease will remain in effect until the cessation of production; or (ii) the existing lease is renewed; or (iii) the lease is contained within a Federal unit. Based on our plans to develop our operated acreage and the current pace of drilling in the Williston Basin, we do not believe lease expirations will materially affect our acreage positions. The following table sets forth the gross and net acres of undeveloped land subject to leases that will expire over the next three years:

	Expiring Acreage
Year Ending	Gross		Net
December 31, 2015		25,763		18,092
December 31, 2016		11,591		4,549
December 31, 2017		14,853		5,942

Unproved Properties

We historically have acquired our properties by purchasing individual or small groups of leases directly from mineral owners or from landmen or lease brokers, which leases historically have not been subject to specified drilling projects. We believe that the majority of our unproved properties will become subject to depletion within the next five years by proving up reserves through exploration and development activities, by impairing acreage that will expire before we can explore or develop it further, or by determining that further exploration and development activity will not occur. The timing by which all other properties will become subject to depletion will depend upon the timing of future drilling activities and delineation of our reserves.

Production Methods; Marketing and Customers

The principal products produced by us are oil and natural gas. These products are marketed and sold primarily to purchasers that have access to nearby pipeline facilities, refineries or other markets. Typically, both oil and natural gas are sold at the wellhead under contracts at negotiated prices based upon factors normally considered in the industry such as distance from well to pipeline, pressure, and quality. We rely on our internal marketing group to sell all of our operated production. We currently have no long-term fixed-price physical delivery contracts in place.

Commensurate with our growth in oil production, we have diversified our oil purchasers. We sell our oil production to third-party marketing companies and a regional pipeline entity that also sells to these and other marketing companies. During the year ended December 31, 2014, we had sales to two purchasers that exceeded 10% of our total oil and natural gas revenue, whereby such purchasers purchased 59% and 22%, respectively, of our total oil and natural gas revenue. Although a substantial portion of our production is purchased by these customers, we do not believe the loss of any one customer would have a material adverse effect on our business as there are other potential customers for our production who are accessible to us.

Our results of operations and financial condition are significantly affected by oil and natural gas commodity prices, which can fluctuate dramatically. The market for oil and natural gas we produce depends on factors beyond our control, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of natural gas pipelines and other transportation facilities, demand for oil and natural gas, the marketing of competitive fuels and the effects of state and federal regulation. The oil and natural gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.

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We have historically used financial hedges to limit our overall exposure to fluctuations in oil prices but the hedging arrangements may also reduce our potential cash flows by limiting our exposure to commodity price increases. Our hedges are intended to mitigate the risk of a reduction in cash flows that may affect our ability to meet our obligations and capital expenditure budget while at the same time ensuring an acceptable rate of return on our investments. Under the terms of our revolving credit facility, we may hedge up to 60% of our forecasted production from our proved oil and natural gas reserves.

We do not currently have firm capacity on pipelines or rail loading facilities that transport oil and natural gas out of the Williston Basin. As a result, we will continue to be affected by changes in the price received locally versus prices at quoted market centers, including WTI. This differential can vary widely because of changes in supply and demand locally and at the market centers as well as the utilization of transportation capacity between these points. During 2014, we experienced differentials ranging from $6.00 per Bbl to $17.00 per Bbl. We are not currently able to hedge this differential using financial instruments, which reduces the effectiveness of our hedges that are based on WTI prices.

Competition

The oil and natural gas industry is intensely competitive, particularly with respect to the acquisition of prospective oil and natural gas properties and oil and natural gas reserves. Our ability to effectively compete is dependent on our geological, geophysical and engineering expertise and our financial resources. We compete against a substantial number of major and independent oil and natural gas companies that have larger technical staffs and greater financial and operational resources than we do. Many of these companies not only engage in the acquisition, exploration, development and production of oil and natural gas reserves, but also have refining operations, market refined products and generate electricity. We also compete with other oil and natural gas companies to secure drilling rigs and other equipment necessary for drilling and completion of wells. Generally, as oil and natural gas prices decline, access to additional drilling equipment and completion services becomes more available. Conversely, as commodity prices increase, drilling equipment, may be in short supply from time to time. See Item 1A. Risk Factors — Competition in obtaining rights to explore and develop oil and natural gas reserves and to market our production may impair our business.

Title to Properties

As is customary in the oil and natural gas industry, we initially conduct a preliminary review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant title defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with general industry standards. Prior to completing an acquisition of producing oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of the properties, we may obtain a title opinion or review previously obtained title opinions. Our oil and natural gas properties are subject to customary royalty and other interests, liens to secure borrowings under our revolving credit facility, liens for current taxes and other burdens, which we believe do not materially interfere with the use or affect our carrying value of the properties. Please see Item 1A. Risk Factors—We may incur losses as a result of title defects in the properties in which we invest.

Seasonality

Winter weather conditions and lease stipulations can limit or temporarily halt our drilling and producing activities and other oil and natural gas operations. These constraints and the resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operating and capital costs. Such seasonal anomalies can also pose challenges for meeting our well drilling objectives and may increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay or temporarily halt our operations.

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Governmental Regulation and Environmental Matters

Our operations are subject to various rules, regulations and limitations impacting the oil and natural gas exploration and production industry as a whole.

Regulation of Oil and Natural Gas Production

Our oil and natural gas exploration, production and related operations, when developed, are subject to extensive rules and regulations promulgated by federal, state, tribal and local authorities and agencies. For example, North Dakota and Montana require permits for drilling operations, drilling bonds and reports concerning operations. Among the other requirements relating to our exploration and production of oil and natural gas are statutes or regulations addressing conservation matters, including the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, and the spacing, plugging and abandonment of such wells. Failure to comply with any such rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry will most likely increase our cost of doing business and may affect our profitability. Although we believe we are currently in substantial compliance with all applicable laws and regulations, because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws. Significant expenditures may be required to comply with governmental laws and regulations and may have a material adverse effect on our financial condition and results of operations.

Environmental Matters

Our operations and properties are subject to extensive and changing federal, state and local laws and regulations relating to environmental protection, including the generation, storage, handling, emission, transportation and discharge of materials into the environment, and relating to safety and health. The recent trend in environmental legislation and regulation generally is toward stricter standards, and this trend will likely continue. These laws and regulations may:

• require the acquisition of a permit or other authorization before construction or drilling commences and for certain other activities;

• limit or prohibit construction, drilling and other activities on certain lands lying within wilderness and other protected areas; and

• impose substantial liabilities for any pollution resulting from our operations.

The permits required for our operations may be subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce their regulations, and violations are subject to fines, injunctions, or both. In management’s opinion, we are in substantial compliance with current applicable environmental laws and regulations, and have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on us, as well as the oil and natural gas industry in general.

The following is a summary of some of the existing laws, rules and regulations to which our operations are subject.

The Comprehensive Environmental, Response, Compensation, and Liability Act (CERCLA) and comparable state statutes impose strict, joint and several liability on owners and operators of sites and on persons who disposed of or arranged for the disposal of “hazardous substances” found at such sites. It is not uncommon for the neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. The Federal Resource Conservation and Recovery Act (RCRA) and comparable state statutes govern the disposal of “solid waste” and “hazardous waste” and authorize the imposition of substantial fines and penalties for noncompliance. Although CERCLA currently excludes petroleum from its definition of “hazardous substance,” state laws affecting our operations may impose clean-up liability relating to petroleum and petroleum related products. In addition, certain oil field wastes currently are classified as “non-hazardous” under RCRA such exploration and production wastes could be reclassified as hazardous wastes thereby making such wastes subject to more stringent handling and disposal requirements.

The federal Safe Drinking Water Act (SDWA) and the Underground Injection Control (UIC) program promulgated under the SDWA and state programs regulate the drilling and operation of salt water disposal wells. The Environmental Protection Agency (EPA) directly administers the UIC program in some states, and in others it is delegated to the state for administering. Permits must be obtained before drilling salt water disposal wells, and casing integrity monitoring must be conducted periodically to ensure the casing is not leaking salt water to groundwater. Contamination of groundwater by oil and natural gas drilling, production, and related operations may result in fines, penalties, and remediation costs, among other sanctions and liabilities under the SDWA and state laws. In addition, third party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury

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Our operations are also subject to the federal Clean Water Act and analogous state laws. The Clean Water Act and similar state acts regulate discharges of wastewater, oil, and other pollutants to surface water bodies, such as lakes, rivers, wetlands, and streams. Failure to obtain permits for such discharges could result in civil and criminal penalties, orders to cease such discharges, and costs to remediate and pay natural resources damages. Discharges regulated under the Clean Water Act include certain discharges of storm water runoff. This storm water discharge program requires covered facilities to obtain individual permits, or seek coverage under a general permit. Some of our properties may require permits for discharges of storm water runoff and, as part of our overall evaluation of our current operations, we will apply for storm water discharge permit coverage and updating storm water discharge management practices at some of our facilities. We believe that we will be able to obtain, or be included under, these permits, where necessary, and make minor modifications to existing facilities and operations that would not have a material effect on us. Water discharge laws also require the preparation and implementation of Spill Prevention, Control, and Countermeasure Plans in connection with on-site storage of significant quantities of oil.

The federal Clean Air Act and comparable state laws regulate emissions of various air pollutants through permitting programs and the imposition of control requirements. For example, the EPA has developed and continues to develop stringent regulations governing emissions of toxic air pollutants at specified sources. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. Our operations, or the operations of service companies engaged by us, may be, in certain circumstances and locations, subject to permits and restrictions under these statutes for emissions of air pollutants.

The Endangered Species Act (ESA) seeks to ensure that activities do not jeopardize endangered or threatened animal, fish and plant species, nor destroy or modify the critical habitat of such species. Under the ESA, neither exploration and production operations, nor related federal agency actions may significantly impair or jeopardize the species or its habitat. Various civil and criminal penalties may be imposed for violations. Other statutes that protect animal and plant species, natural areas or other unique sites and that may apply to our operations include, but are not necessarily limited to, the Fish and Wildlife Coordination Act, the Fishery Conservation and Management Act, the Migratory Bird Treaty Act and the National Historic Preservation Act. Although we believe that our operations are in substantial compliance with such statutes, any change in these statutes or any reclassification of a species as endangered could subject us to significant expenses to modify our operations or could force us to discontinue certain operations altogether.

For additional discussion, see Item 1A. Risk Factors – We are subject to various governmental regulations and environmental risks that may cause us to incur substantial costs.

Hydraulic Fracturing Concerns

The practice of hydraulic fracturing has recently become a significant focus of some environmentalists, regulators and the general public. Concerns over potential hazards associated with the use of hydraulic fracturing and its impact on the environment have been raised at all levels of government, including federal, state and local. There have been reports associating hydraulic fracturing with groundwater contamination, improper waste disposal, poor air quality and earthquakes. Hydraulic fracturing requires the use and disposal of significant quantities of water, and public concern has been growing over its possible effects on drinking water supplies, as well as the adequacy of supply and of appropriate disposal outlets. Hydraulic fracturing techniques have been used by the industry for many years, and, currently, more than 90% of all oil and natural gas wells drilled in the U.S. employ hydraulic fracturing. We and our operating partners strive to adopt best practices and industry standards and comply with all regulatory requirements regarding well construction and operation. We have, and believe our operating partners have, established processes to help ensure that hydraulic fracturing does not pose a meaningful risk to water supplies.

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Potential Rulemaking

Although hydraulic fracturing is regulated primarily at the state level, governments and agencies at all levels from federal to municipal are conducting studies and considering regulations. For example, in 2011, the U.S. Secretary of Energy formed the Shale Gas Production Subcommittee, a subcommittee of the Secretary of Energy Advisory Board. The Subcommittee was charged with making recommendations to improve the safety and environmental performance of hydraulic fracturing. On August 18, 2011, the Subcommittee issued its Ninety Day Report (the “Report”), which focused exclusively on the production of natural gas (and some liquid hydrocarbons) from shale formations with hydraulic fracturing stimulation in either vertical or horizontal wells. The Subcommittee identified four primary areas of concern including possible water pollution, air pollution, disruption of the community during production, and potential for adverse impact on communities and ecosystems. The Subcommittee also set forth a list of recommendations addressing, among other things, communications, air quality, protection of water supply and quality, disclosure of fracturing fluid composition, reduction of diesel fuel use, continuous development of best practices, and federal sponsorship of research and development with respect to unconventional gas. The Subcommittee issued its Final Report in November 2011, which recommended implementation of the Subcommittee’s recommendations by federal and state agencies.

In 2013, the Bureau of Land Management (BLM) proposed regulations governing hydraulic fracturing on federal lands. The regulations would require: (1) public disclosure of chemicals used in hydraulic fracturing operations; (2) assurances on well-bore integrity to verify that fluids used in wells during fracturing operations are not escaping; and (3) development of a water management plan in place for handling fracturing fluids that flow back to the surface.

During 2012, the EPA proposed new guidelines under the SDWA regarding the issuance of permits for the use of diesel fuel as a component in hydraulic fracturing activities. The draft guidance outlines for EPA permit writers, where the EPA is the permitting authority, requirements for diesel fuels used for hydraulic fracturing wells, technical recommendations for permitting those wells, and a description of diesel fuels for EPA underground injection control permitting. The EPA published the final version of this guidance on February 12, 2014.

The EPA is currently studying the potential impacts of hydraulic fracturing on drinking water resources. Results are expected to be released in a draft for public and peer review in 2015. As of January 1, 2015, moreover, newly fractured or refractured natural gas wells must use emissions reduction technology known as “green completions" to comply with the EPA’s New Source Performance Standards for oil and natural gas operations.

We continue to monitor new and proposed legislation and regulations to assess the potential impact on our business. Any additional federal, state or local restrictions on hydraulic fracturing that may be imposed in areas where we conduct business could result in substantial incremental operating, capital and compliance costs as well as delay our ability to develop oil and natural gas reserves. For additional discussion, see Item 1A. Risk Factors —Federal and state legislative and regulatory initiatives relating to hydraulic fracturing legislation could result in increased costs and additional operating restrictions or delays, or restrict our access to oil and natural gas reserves.

Climate Change

Significant studies and research have been devoted to climate change and global warming, and climate change has developed into a major political issue in the United States and globally. Certain research suggests that greenhouse gas emissions contribute to climate change and pose a threat to the environment. Recent scientific research and political debate has focused in part on carbon dioxide and methane incidental to oil and natural gas exploration and production. Many states and the federal government have enacted legislation directed at controlling greenhouse gas emissions, and future legislation and regulation could impose additional restrictions or requirements in connection with our drilling and production activities and favor use of alternative energy sources, which could increase operating costs and demand for oil products. As such, our business could be materially adversely affected by domestic and international legislation targeted at controlling climate change. For additional discussion, see Item 1A. Risk Factors — The adoption of climate change legislation or regulations could result in increased operating costs, create delays in our obtaining air pollution permits for new or modified facilities, and result in reduced demand for the oil and natural gas we produce.

Employees

We currently have 42 full time employees. Our Chief Executive Officer, McAndrew Rudisill, and our Chief Financial Officer, Ryan Smith, are responsible for all material employee related policy-making decisions. None of our employees are subject to a collective bargaining agreement. If drilling and production activities continue to increase, we may hire additional technical or administrative personnel as appropriate. We are using and will continue to use the services of independent consultants and contractors to perform various professional services, particularly in the area of reservoir engineering, well drilling and well completion operations.

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Company Background and Office Locations

We were originally incorporated in Delaware on July 28, 2004 and were recapitalized on April 16, 2010, when we began oil and natural gas exploration and development activities.  We subsequently reincorporated in Montana on May 31, 2011. On June 11, 2014, our stockholders approved a measure to change our state of incorporation from Montana to Delaware. On June 11, 2014, we consummated a merger with our wholly owned subsidiary and, as a result, reincorporated as a Delaware corporation. Our executive offices are located at 1600 Broadway Avenue, Suite 1360, Denver, Colorado 80202.

Financial Information About Segments and Geographic Areas

Our leaseholds consist of a single natural resource play in the Williston Basin in North Dakota and Montana. We have segregated the area into developed and undeveloped acreage and productive and exploratory wells in Item 1. Business. All of our oil and natural gas properties and related operations are located onshore in the United States, and management has determined that we have one reportable segment. See Item 8. Financial Statements and Supplementary Data.

Available Information — Reports to Security Holders

Our website address is www.emeraldoil.com. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, Section 16 reports for officers and directors, and amendments to those reports are available on our website, free of charge, under “Investors” as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC. These filings are also available to the public at the SEC’s Public Reference Room at 100 F Street, NE, Room 1580, Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Electronic filings with the SEC are also available on the SEC website at www.sec.gov.

We have also posted to our website under “Investors” charters for our Audit Committee, Compensation Committee and Governance/Nominating Committee, our Code of Ethics and Business Conduct, in addition to all pertinent contact information. We intend to satisfy the disclosure requirements of Item 5.05 of Form 8-K regarding any amendment to, or waiver of, a provision of our Code of Ethics and Business Conduct that applies to our principal executive officer, principal financial officer, principal accounting officer or controller and relates to any element of the definition of code of ethics set forth in Item 406(b) of Regulation S-K by posting such information under the “Investors” tab of our website at www.emeraldoil.com. Information contained on our website is not incorporated by reference into this Annual Report and you should not consider information contained on our website as part of this Annual Report.

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Item 1A.   Risk Factors

Described below are certain risks that we believe are applicable to our business and the oil and gas industry in which we operate. You should carefully consider the risks, uncertainties and other factors described below and all other information set forth in this Annual Report on Form 10-K. Any of the factors could materially and adversely affect our business, financial condition, operating results and prospects and could negatively impact the market price of our common stock. Also, you should be aware that the risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties, of which we are not yet aware, or that we currently consider to be immaterial may also impair our business operations.

Prices and markets for oil and natural gas are unpredictable and tend to fluctuate significantly, which could reduce profitability, growth and the value of our business.

Oil and natural gas are commodities, the prices of which are determined based on world demand, supply and other factors, all of which are beyond our control. These factors include:

· the domestic and foreign supply of oil and natural gas;

· the current level of prices and expectations about future prices of oil and natural gas;

· the level of global oil and natural gas exploration and production;

· the cost of exploring for, developing, producing and delivering oil and natural gas;

· the price of foreign oil and natural gas imports;

· political and economic conditions in oil producing regions, including the Middle East, Africa, South America and Russia;

· the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

· speculative trading in oil and natural gas derivative contracts;

· the level of consumer product demand;

· weather conditions and other natural disasters;

· risks associated with operating drilling rigs;

· technological advances affecting energy consumption;

· domestic and foreign governmental regulations and taxes;

· the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East;

· the availability, proximity and capacity of oil and natural gas transportation, processing, storage and refining facilities;

· the price and availability of alternative fuels; and

· overall domestic and global economic conditions.

Oil prices and natural gas prices do not necessarily fluctuate in direct relation to each other. Because approximately 87% of our estimated proved reserves as of December 31, 2014 were oil, our financial results are more sensitive to movements in oil prices. The price of oil has been extremely volatile and we expect this volatility to continue. During the year ended December 31, 2014, the daily NYMEX WTI oil spot price ranged from a high of $107.26 per Bbl to a low of $53.27 per Bbl and the NYMEX natural gas Henry Hub spot price ranged from a high of $6.15 per MMBtu to a low of $2.89 per MMBtu.

Further, world prices for oil and natural gas have fluctuated widely in recent years, and we expect that prices will fluctuate in the future. Price fluctuations will have a significant impact upon our revenue, the return from our reserves and on our financial condition generally. Price fluctuations for oil and natural gas commodities may also impact the investment market for companies engaged in the oil and natural gas industry. Prices may not remain at current levels. Decreases in the prices of oil and natural gas may have a material adverse effect on our financial condition, the future results of our operations and quantities of reserves recoverable on an economic basis. A significant decrease in oil and natural gas prices could also adversely impact our ability to raise additional capital to pursue future drilling activities.

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Lower oil and natural gas prices have reduced and may further reduce the amount of oil and natural gas that we can produce economically and may cause the value of our proved reserves at future reporting dates to decline. Specifically, a decline in the value of our reserves may reduce the borrowing base available to us under our senior secured revolving credit facility, and, should the value of our reserves decline below our recorded costs as measured by the ceiling test, we would be required to record a non-cash impairment charge in our financial statements. Additionally, an extended decline in commodity process could lead us to further reduce our 2015 capital expenditure budget and scale back our exploration and development activities.

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

As of December 31, 2014, we had commodity price derivative agreements on approximately 1,333 Bbls/d of oil hedged with fixed price swaps during the first quarter of 2015. These hedges may be inadequate to protect us from continuing and prolonged declines in the price of oil and natural gas. To the extent that the prices of oil and natural gas remain at current levels or decline further, we will not be able to hedge future production at the same level as our current hedges and our results of operations and financial condition would be negatively impacted.

Lower oil and natural gas prices, decreases in value of undeveloped acreage, lease expirations and material changes to our plans of development may cause us to record ceiling test write-downs.

We use the full cost method of accounting to account for our oil and natural gas operations. Accordingly, we capitalize the cost to acquire, explore for and develop oil and natural gas properties. Under full cost accounting rules, the net capitalized costs of oil and natural gas properties may not exceed a “full cost ceiling” which is based upon the present value of estimated future net cash flows from proved reserves, including the effect of hedges in place, discounted at 10%, plus the lower of cost or fair market value of unproved properties. If at the end of any fiscal period we determine that the net capitalized costs of oil and natural gas properties exceed the full cost ceiling, we must charge the amount of the excess to earnings in the period then ended. This is called a “ceiling test write-down.” This charge does not impact cash flow from operating activities, but does reduce our net income and stockholders’ equity. We may recognize write-downs in the future if commodity prices decline or if we experience substantial downward adjustments to our estimated proved reserves.

As a result of currently prevailing low commodity prices and their effect on the proved reserve values of properties we acquired during 2014, we recorded a non-cash ceiling test impairment for the 2014 fourth quarter, as reflected in our financial statements for the year ended December 31, 2014. The impairment charge affected our reported net income but did not reduce our cash flow. Continued write downs of oil and natural gas properties may occur until such time as commodity prices have recovered, and remain 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.

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

As of December 31, 2014, we have identified approximately 890 net potential drilling locations on our acreage prospective for oil in the Bakken, Three Forks and Pronghorn Sand formations, based on industry accepted well down-spacing assumptions, including 1,280-acre DSUs in the Williston Basin. These drilling locations, including those without proved undeveloped reserves, represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, construction of infrastructure, inclement weather, regulatory changes and approvals, oil and natural gas prices, costs, drilling results and the availability of water. Further, our identified potential drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation. We cannot predict in advance of drilling and testing whether any particular drilling location will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in production from the well or abandonment of the well. If we drill additional wells that we identify as dry holes in our current and future drilling locations, our drilling success rate may decline and materially harm our business. Because of these uncertainties, we do not know if the potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

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Successful exploitation of the Williston Basin is subject to risks related to horizontal drilling and completion techniques.

Operations in the Williston Basin involve utilizing the latest drilling and completion techniques, including horizontal drilling and completion techniques, to generate the highest possible cumulative recoveries and therefore generate the highest possible returns. Risks that are encountered while drilling include, but are not limited to, landing the well bore in the desired drilling zone, staying in the zone while drilling horizontally through the formation, running casing the entire length of the well bore and being able to run tools and other equipment consistently through the horizontal well bore. Completion risks include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the well bore during completion operations, and successfully cleaning out the well bore after completion of the final fracture stimulation stage. Ultimately, the success of these latest drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period.

The drilling and completion of a well in the Williston Basin typically costs between $7.5 million and $12.0 million on a gross basis, which is significantly more expensive than a typical onshore conventional well. Accordingly, unsuccessful exploration or development activity affecting even a small number of wells could have a significant impact on our results of operations.

Delays in the development of or production curtailment at our material properties may adversely affect our financial position and results of operations.

The size of our operations and our capital expenditures budget limit the number of properties that we can develop in any given year. Complications in the development of any single major well or infrastructure installation may result in a material adverse effect on our financial condition and results of operations. In addition, relatively few wells contribute a substantial portion of our production. If we were to experience operational problems or adverse commodity prices resulting in the curtailment of production in any of these wells, our total production levels would be adversely affected, which would have a material adverse effect on our financial condition and results of operations.

The Williston Basin oil price differential could have adverse impacts on our revenues.

Generally, oil produced from the Bakken formation in North Dakota is high quality (characterized by an American Petroleum Institute gravity, or API gravity, between 36 to 44 degrees, which is comparable to West Texas Intermediate, or WTI, oil). However, due to takeaway constraints, oil prices in the Williston Basin ranged from $6.00 to $17.00 less per Bbl than prices for other areas in the United States during 2014. This discount, or differential, may widen in the future, which would reduce the price we would receive for our production.

Drilling and completion costs for the wells we drill in the Williston Basin are comparable to other areas where there is no price differential. As a result of this reverse leverage effect, a significant, prolonged downturn in oil prices on a national basis could result in a ceiling limitation write-down of the oil and natural gas properties we hold. Such a price downturn also could reduce cash flow from our Williston Basin properties and adversely impact our ability to participate fully in other drilling. Our production in other areas could also be affected by adverse changes in differentials. In addition, changes in differentials could make it more difficult for us to effectively hedge our exposure to changes in commodity prices.

Estimates of proved oil and natural gas reserves are uncertain and any material inaccuracies in these reserve estimates will materially affect the quantities and the value of our reserves.

This Annual Report on Form 10-K contains estimates of our proved oil and natural gas reserves. The estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and natural gas reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from those estimated. Any significant variance could materially affect the estimated quantities and the value of our reserves. Our properties may also be susceptible to hydrocarbon drainage from production by other operators on adjacent properties. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

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At December 31, 2014, approximately 43% of our estimated reserves were classified as proved undeveloped. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data assumes that we will make significant capital expenditures to develop our reserves. Although we have prepared estimates of these oil and natural gas reserves and the costs associated with development of these reserves in accordance with SEC regulations, actual capital expenditures will likely vary from estimated capital expenditures, development may not occur as scheduled and actual results may not be as estimated.

Exploration for oil and natural gas is risky and may not be commercially successful, and the advanced technologies we and our operating partners use cannot eliminate exploration risk, which could impair our ability to generate revenues from our operations.

Our future success will depend on the success of our exploration, development and production program. Oil and natural gas exploration involves a high degree of risk. These risks are more acute in the early stages of exploration. Our ability to generate a return on our investments, revenues and our resulting financial performance are significantly affected by the prices we receive for oil and natural gas produced from wells on our acreage. Especially in recent years, the prices at which oil and natural gas trade in the open market have experienced significant volatility, and will likely continue to fluctuate in the foreseeable future due to a variety of factors.

Our expenditures on exploration may not result in new discoveries of oil or natural gas in commercially viable quantities. It is difficult to project the costs of implementing an exploratory drilling program due to the inherent uncertainties of drilling in unknown formations, the costs associated with encountering various drilling conditions, such as over-pressured zones and tools lost in the hole, and changes in drilling plans and locations as a result of prior exploratory wells or additional seismic data and interpretations thereof.

Even when used and properly interpreted, three-dimensional (3-D) seismic data and visualization techniques only assist geoscientists in identifying subsurface structures and hydrocarbon indicators. These techniques do not allow the interpreter to know conclusively if hydrocarbons are present or economically producible. In addition, the use of 3-D seismic data becomes less reliable when used at increasing depths. We could incur losses as a result of expenditures on unsuccessful wells. If exploration costs exceed estimates, or if exploration efforts do not produce results which meet expectations, the exploration efforts may not be commercially successful, which could adversely impact our ability to generate revenues from our operations.

We may not be able to develop oil and natural gas reserves on an economically viable basis, and our reserves and production may decline as a result.

If we succeed in discovering oil and natural gas reserves, these reserves may not be capable of the production levels we project or in sufficient quantities to be commercially viable. On a long-term basis, our viability depends on our ability to find or acquire, develop and commercially produce additional oil and natural gas reserves. Without the addition of reserves through acquisition, exploration or development activities, our reserves and production will decline over time as reserves are produced. Our future reserves will depend not only on our ability to develop then-existing properties, but also on our operating partners’ ability to identify and acquire additional suitable producing properties or prospects, to find markets for the oil and natural gas we may develop and to effectively distribute our production.

Future oil and natural gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-ins of connected wells resulting from extreme weather conditions, problems in storage and distribution and adverse geological and mechanical conditions. We will not be able to completely eliminate these conditions in any case. Therefore, these conditions could diminish our revenue and cash flow levels and result in the impairment of our oil and natural gas interests.

We may not be able to drill wells on a substantial portion of our acreage.

We may not be able to drill on a substantial portion of our acreage for various reasons. We may not generate or be able to raise sufficient capital to do so. Future deterioration in commodities pricing may also make drilling some acreage uneconomic. Our actual drilling activities and future drilling budget will depend on drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, lease expirations, gathering system and pipeline transportation constraints, regulatory approvals and other factors. In addition, any drilling activities we are able to conduct may not be successful or add additional proved reserves to our overall proved reserves, which could have a material adverse effect on our future business, financial condition and results of operations.

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

A large portion of our acreage is not currently held by production. Unless production in paying quantities is established on units containing these leases during their terms, these leases will expire. If our leases expire, we will lose our right to develop the related properties. Our drilling plans for these areas are subject to change based upon various factors, many of which are beyond our control, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints, and regulatory approvals. Further, some of our acreage is located in sections where we do not hold the majority of the acreage and therefore it is likely that we will not be named operator of these sections. On our acreage that we do not operate, we have less control over the timing of drilling and there is therefore additional risk of expirations occurring in those sections.

Shortages of equipment, services and qualified personnel could reduce our cash flow and adversely affect results of operations.

The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers, and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices and activity levels in new regions, causing periodic shortages. These problems can be particularly severe in certain regions such as the Williston Basin. For example, during periods of high oil and natural gas prices, the demand for drilling rigs and equipment has increased along with increased activity levels, which may result in shortages of equipment. In addition, there has been a shortage of hydraulic fracturing capacity in recent years in the area in which we operate. This shortage in hydraulic fracturing capacity could occur in the future. Higher oil and natural gas prices generally stimulate increased demand and result in increased prices for drilling rigs, crews and associated supplies, oilfield equipment and services, and personnel. These types of shortages and subsequent price increases could significantly decrease our profit margin, cash flow and operating results and/or restrict or delay our ability to drill those wells and conduct those operations that we currently have planned and budgeted, causing us to miss our forecasts and projections.

Our lack of diversification will increase the risk of an investment in us and our financial condition and results of operations may deteriorate if we fail to diversify.

Our business is focused primarily on a limited number of properties in North Dakota and Montana. We may choose to limit our focus to a single geographic area such as the Williston Basin, which could limit our flexibility. We previously committed to joint ventures with third parties to acquire and develop acreage; we may continue to participate in joint ventures in the future, although we intend to focus on operating our own properties. Our required capital commitments may grow if the opportunity presents itself and will depend upon the results of initial testing and development activities. Larger companies have the ability to manage their risk by diversification. However, we lack diversification in terms of both the nature and geographic scope of our business. As a result, we will likely be impacted more acutely by factors affecting our industry or the regions in which we operate than if our business was more diversified, enhancing our risk profile. For example, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in the area caused by governmental regulation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services market limitations or interruption of the processing or transportation of oil or natural gas. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Williston Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. If we cannot diversify our operations, our financial condition and results of operations could deteriorate.

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Our ability to sell our production and/or receive market prices for our production may be adversely affected by transportation capacity constraints and interruptions.

If the amount of oil or natural gas being produced by us and others exceeds the capacity of the various transportation pipelines and gathering systems currently available in our operating areas, it will be necessary for new transportation pipelines and gathering systems to be built. In the case of oil and condensate, it may be necessary for us to rely more heavily on trucks to transport our production, which is more expensive and less efficient than transportation via pipeline. Currently, we anticipate that additional pipeline capacity will be required in the Williston Basin to transport oil and condensate production, which increased substantially during 2014 and is expected to continue to increase. The construction of new pipelines and gathering systems is capital intensive and construction may be postponed, interrupted or cancelled in response to changing economic conditions and the availability and cost of capital. In addition, capital constraints could limit our ability to build gathering systems to transport our production to transportation pipelines. In such event, costs to transport our production may increase materially or we might have to shut in our wells awaiting a pipeline connection or capacity and/or sell our production at much lower prices than market or than we currently project, which would adversely affect our results of operations. A portion of our production may also be interrupted, or shut in, from time to time for numerous other reasons, including as a result of weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions.

Competition in obtaining rights to explore and develop oil and natural gas reserves and to market our production may impair our business.

The oil and natural gas industry is highly competitive. Other oil and natural gas companies may seek to acquire oil and natural gas leases and other properties and services we intend to target with our investments. This competition is increasingly intense as prices of oil and natural gas rise. Additionally, other companies engaged in our line of business may compete with us from time to time in obtaining capital from investors or in funding joint ventures with our prospective partners. Competitors include a variety of potential investors and larger companies, which, in particular, may have access to greater resources, may be more successful in the recruitment and retention of qualified employees and may conduct their own refining and petroleum marketing operations, which may give them a competitive advantage. In addition, actual or potential competitors may be strengthened through the acquisition of additional assets and interests. If we are unable to compete effectively or adequately respond to competitive pressures, this inability may materially adversely affect our results of operation and financial condition.

Strategic relationships upon which we may rely are subject to change, which may diminish our ability to conduct our operations.

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 depends on developing and maintaining close working relationships with industry participants, our ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment. These realities are subject to change and may impair our ability to grow.

To further develop our business, we may endeavor to use the business relationships of our management team to enter into strategic relationships, which may take the form of joint ventures with other private parties and contractual arrangements with other oil and natural gas companies, including those that supply equipment and other resources that we will use in our business. Our ability to successfully operate joint ventures depends on a variety of factors, many of which will be entirely outside our control. We may not be able to establish strategic relationships, or if established, we may not be able to maintain them. In addition, the dynamics of our relationships with strategic partners may require us to incur expenses or undertake activities we would not otherwise be inclined to undertake in order to fulfill our obligations to these partners or maintain our relationships. If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations.

Our strategy includes acquisitions of oil and natural gas properties, and our failure to identify or complete future acquisitions successfully could reduce our earnings and hamper our growth.

We may be unable to identify properties for acquisition or to make acquisitions on terms that we consider economically acceptable. There is intense competition for acquisition opportunities in the oil and natural gas industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. The completion and pursuit of acquisitions may be dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Our ability to grow through acquisitions will require us to continue to invest in operations, financial and management information systems and to attract, retain, motivate and effectively manage our employees. The inability to manage the integration of acquisitions effectively could reduce our focus on subsequent acquisitions and current operations, and could negatively impact our results of operations and growth potential. Our financial position and results of operations may fluctuate significantly from period to period as a result of the completion of significant acquisitions during particular periods. If we are not successful in identifying or acquiring any material property interests, our earnings could be reduced and our growth could be restricted.

We may engage in bidding and negotiating to complete successful acquisitions. We may be required to alter or increase substantially our capitalization to finance these acquisitions through the use of cash on hand, the issuance of debt or equity securities, the sale of production payments, the sale of non-strategic assets, the borrowing of funds or otherwise. If we were to proceed with one or more acquisitions involving the issuance of our common stock, our stockholders would suffer dilution of their interests. Furthermore, our decision to acquire properties that are substantially different in operating or geologic characteristics or geographic locations from areas with which our staff is familiar may impact our productivity in such areas.

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We may have difficulty integrating and managing the growth associated with our recent acquisitions.

Our recent acquisitions are expected to result in a significant growth in our assets, reserves and revenues and may place a significant strain on our financial, technical, operational and administrative resources. We may not be able to integrate the operations of the acquired assets without increases in costs, losses in revenues or other difficulties. In addition, we may not be able to realize the operating efficiencies, synergies, costs savings or other benefits expected from such acquisitions. Any unexpected costs or delays incurred in connection with such integration could have an adverse effect on our business, results of operations or financial condition. We have hired and intend to hire new employees that we expect will be required to manage our operations, and we plan to add resources as needed as we scale up our business. However, we may experience difficulties in finding additional qualified personnel. In an effort to stay on schedule with our planned activities, we may supplement our staff with contract and consultant personnel until we are able to hire new employees. Our ability to continue to grow after these acquisitions will depend upon a number of factors, including our ability to identify and acquire new exploratory prospects and other acquisition targets, our ability to develop then existing prospects, our ability to successfully adopt an operated approach, our ability to continue to retain and attract skilled personnel, the results of our drilling program and acquisition efforts, hydrocarbon prices and access to capital. We may not be successful in achieving or managing growth, and any such failure could have a material adverse effect on us.

Acquisitions may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities.

Our recent growth is due in large part to acquisitions of producing properties and undeveloped leasehold. We expect acquisitions to be instrumental to our future growth. Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, future oil and natural gas prices, operating costs and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we perform a review of the acquired properties that we believe is generally consistent with industry practices. However, such a review will not reveal all existing or potential problems, and does not involve a review of seismic data or independent environmental testing. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and limitations, including any structural, subsurface and environmental problems that may exist or arise. As a result of these factors, we may not be able to acquire oil and natural gas properties that contain economically recoverable reserves or be able to complete future acquisitions on terms that we believe are acceptable or that, even if completed, do not contain problems that reduce the value of acquired property.

We may incur losses as a result of title defects in the properties in which we invest.

Title to oil and natural gas interests is often not capable of conclusive determination without incurring substantial expense. Title defects may exist in many of our oil and natural gas interests. In addition, we may be unable to obtain adequate insurance for title defects on a commercially reasonable basis or at all. If title defects do exist, it is possible that we may lose all or a portion of our right, title and interests in and to the properties to which the title defects relate and suffer a financial loss. If our property rights are reduced, our ability to conduct our exploration, development and production activities may be impaired.

It is our practice in acquiring oil and natural gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest. Rather, we rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest.

Prior to the drilling of an oil or natural gas well, however, it is the normal practice in our industry for the operator of the well to conduct a preliminary title review prior to drilling to ensure there are no obvious defects in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may delay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability in the future to increase production and reserves. Additionally, undeveloped acreage has greater risk of title defects than developed acreage.

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If we are not able to generate sufficient funds from our operations and other financing sources, we may not be able to finance our planned development activity, acquisitions or service our debt.

We have been dependent on debt and equity financing to fund our cash needs that are not funded from operations or the sale of assets, and we will continue to incur additional indebtedness to fund our operations. Low commodity prices, production problems, disappointing drilling results and other factors beyond our control could reduce our funds from operations and may restrict our ability to obtain additional financing or to pay interest and principal on our debt obligations. Furthermore, we have incurred losses in the past that may affect our ability to obtain financing. Quantifying or predicting the likelihood of any or all of these occurring is difficult in the current domestic and world economy. For these reasons, financing may not be available to us in the future on acceptable terms or at all. In the event additional capital is required but not available on acceptable terms, we would curtail our acquisition, drilling, development and other activities or could be forced to sell some of our assets on an untimely or unfavorable basis.

We may be unable to obtain additional capital that we will require to implement our business plan, which could restrict our ability to grow.

Our revolving credit facility limits our borrowings to the lesser of the borrowing base and the total commitments. Our borrowing base was $250.0 million as of December 31, 2014. Our borrowing base is determined semi-annually, and may also be redetermined at the election of us or the banks between the scheduled redeterminations. Lower oil and natural gas prices may result in a reduction in our borrowing base at the next redetermination, which is scheduled to occur in April 2015. A reduction in our borrowing base could require us to repay any indebtedness in excess of the borrowing base. Additionally, our revolving credit facility contains covenants limiting our ability to incur additional indebtedness and requiring us to maintain certain financial ratios.

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

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

We have a history of losses which may continue and negatively impact our ability to achieve our business objectives.

We incurred net losses of $52,145,225, $10,882,895 ($31,162,092 attributable to common shareholders) and $62,296,099 for the years ended December 31, 2014, 2013 and 2012, respectively. We cannot assure you that we can achieve or sustain profitability on a quarterly or annual basis in the future. Our operations are subject to the risks and competition inherent in the oil and natural gas industry. We cannot assure you that future operations will be profitable. Revenues and profits, if any, will depend upon various factors, including whether we will be able to increase our revenues. We may not achieve our business objectives and the failure to achieve such goals would have an adverse impact on our business, financial condition and result of operations.

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We have debt, trade payables, and other long-term obligations.

Our debt, trade payables, long-term obligations, and related interest and dividend payment requirements and scheduled debt maturities may have important negative consequences. For instance, they could:

· make it more difficult or render us unable to satisfy these or our other financial obligations;

· require us to dedicate a substantial portion of any cash flow from operations to the payment of overriding royalties or interest and principal due under our debt, which will reduce funds available for other business purposes;

· increase our vulnerability to general adverse economic and industry conditions;

· limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

· place us at a competitive disadvantage compared to some of our competitors that have less financial leverage; and

· limit our ability to obtain additional financing required to fund working capital and capital expenditures and for other general corporate purposes.

Our ability to satisfy our financial obligations and commitments depends on our future operating performance and on economic, financial, competitive and other factors, many of which are beyond our control. We cannot provide assurance that our business will generate sufficient cash flow or that future financings will be available to provide sufficient proceeds to meet these obligations. The inability to meet our financial obligations and commitments will impede the successful execution of our business strategy and the maintenance of our economic viability. Oil and natural gas prices are volatile, and low prices have had in the past and could have in the future a material adverse impact on our business. Our revenues, profitability and future growth and the carrying value of our properties depend substantially on the prices we realize for our oil and natural gas production. Our realized prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital.

Restrictive debt covenants could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.

Our revolving credit facility contains a number of significant covenants that, among other things, restrict or limit our ability to:

· pay dividends or distributions on our capital stock;

· make certain loans and investments;

· enter into certain transactions with affiliates;

· create or assume certain liens on our assets;

· merge or to enter into other business combination transactions;

· enter into transactions that would result in a change of control of us; or

· engage in certain other corporate activities.

Also, our revolving credit facility requires us to maintain compliance with specified financial ratios and satisfy certain financial condition tests. Our ability to comply with these ratios and financial condition tests may be affected by events beyond our control, and we cannot assure you that we will meet these ratios and financial condition tests. These financial ratio restrictions and financial condition tests could limit our ability to obtain future financings, make needed capital expenditures, withstand a future downturn in our business or the economy in general or otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under our revolving credit facility impose on us.

A breach of any of these covenants or our inability to comply with the required financial ratios or financial condition tests could result in a default under our revolving credit facility. A default, if not cured or waived, could result in all indebtedness outstanding under our revolving credit facility becoming immediately due and payable. If that should occur, we may not be able to pay all such debt or borrow sufficient funds to refinance it. Even if new financing were then available, it may not be on terms that are acceptable to us. If we were unable to repay those amounts, the lenders could accelerate the maturity of the debt or proceed against any collateral granted to them to secure such defaulted debt.

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We may not be able to effectively manage our growth, which may harm our profitability.

Our strategy envisions expanding our business. If we fail to effectively manage our growth, our financial results could be adversely affected. Growth may place a strain on our management systems and resources. We must continue to refine and expand our business development capabilities, our systems and processes and our access to financing sources. As we grow, we must continue to hire, train, supervise and manage new employees. We may not be able to:

· meet our capital needs;

· expand our systems effectively or efficiently or in a timely manner;

· allocate our human resources optimally;

· identify and hire qualified employees or retain valued employees; or

· incorporate effectively the components of any business that we may acquire in our effort to achieve growth.

If we are unable to manage our growth, our operations and our financial results could be adversely affected by inefficiency, which could diminish our profitability.

Our business may suffer if we do not attract and retain talented personnel.

Our success will depend in large measure on the abilities, expertise, judgment, discretion, integrity and good faith of our management and other personnel in conducting our business. We have a small management team, and the loss of key individuals or the inability to attract and retain suitably qualified personnel could materially adversely impact our business.

Our success depends on the ability of our management, employees and exploration partners to interpret market and geological data correctly and to interpret and respond to economic market and other conditions in order to locate and adopt appropriate investment opportunities, monitor such investments, and ultimately, if required, to successfully divest such investments.

Penalties we may incur could impair our business.

Failure to comply with government regulations could subject us to civil and criminal penalties, could require us to forfeit property rights, and may affect the value of our assets. We may also be required to take corrective actions, such as installing additional equipment or taking other actions, each of which could require us to make substantial capital expenditures. We could also be required to indemnify our employees in connection with any expenses or liabilities that they may incur individually in connection with regulatory action against them. As a result, our future business prospects could deteriorate due to regulatory constraints, and our profitability could be impaired by our obligation to provide such indemnification to our employees.

We may have difficulty distributing our oil and natural gas production, which could harm our financial condition.

In order to sell the oil and natural gas that we are able to produce from the Williston Basin, we may have to make arrangements for storage and distribution to the market. We will rely on local infrastructure and the availability of transportation for storage and shipment of our products, but infrastructure development and storage and transportation facilities may be insufficient for our needs at commercially acceptable terms in the localities in which we operate. The marketability of our oil and natural gas production depends in part on the availability, proximity and capacity of pipeline and rail systems owned by third parties. The lack or unavailability of capacity on these systems and facilities could result in the shut-in of producing wells or the delay, or discontinuance of, development plans for properties. The disruption of third-party pipelines or rail transportation facilities due to labor disputes, maintenance, civil disturbances, public protests, terrorist attacks, cyber-attacks, adverse weather, regulatory developments, equipment failures or accidents, including pipeline ruptures or train derailments, could negatively impact our ability to market and deliver our products and achieve the most favorable prices for our oil and natural gas production. This situation could be exacerbated to the extent that our operations are conducted in remote areas that are difficult to access, such as areas that are distant from shipping and/or pipeline facilities. These factors may affect our ability to explore and develop properties and to store and transport our oil and natural gas production, which may increase our expenses.

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Our hedging activities could result in financial losses or could reduce our net income or increase our net loss, which may adversely affect our business.

In order to manage our exposure to price risks in the marketing of our oil and natural gas production, we may enter into oil and natural gas price hedging arrangements with respect to a portion of expected production that we fund. Such transactions may limit our potential gains and increase our potential losses if oil and natural gas prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose us to the risk of loss in certain circumstances, including instances in which:

· production is less than expected;

· there is a widening of price differentials between delivery points for our production and the delivery point assumed in the hedge arrangement; or

· the counterparties to our hedging agreements fail to perform under the contracts.

Seasonal weather conditions and other factors could adversely affect our ability to conduct drilling activities.

Our operations could be adversely affected by weather conditions and wildlife restrictions on federal leases. In the Williston Basin, drilling and other oil and natural gas activities cannot be conducted as effectively during the winter months. Winter and severe weather conditions limit and may temporarily halt the ability to operate during such conditions. These constraints and the resulting shortages or high costs could delay or temporarily halt our oil and natural gas operations and materially increase our operating and capital costs, which could have a material adverse effect on our business, financial condition, and results of operations.

The inability of our customers and other contractual counterparties to satisfy their obligations to us may have a material and adverse effect on us.

We have various customers for the oil, natural gas and related commodities that we produce as well as various other contractual counterparties, including several financial institutions and affiliates of financial institutions. Domestic and global economic conditions, including the financial condition of financial institutions generally, have weakened in recent years and remain relatively weak. In addition, there continues to be weakness and volatility in domestic and global financial markets relating to the credit crisis in recent years, and corresponding reaction by lenders to risk. These conditions and factors may adversely affect the ability of our customers and other contractual counterparties to pay amounts owed to us from time to time and to otherwise satisfy their contractual obligations to us, as well as their ability to access the credit and capital markets for such purposes.

Moreover, our customers and other contractual counterparties may be unable to satisfy their contractual obligations to us for reasons unrelated to these conditions and factors, such as the unavailability of required facilities or equipment due to mechanical failure or market conditions. Furthermore, if a customer is unable to satisfy its contractual obligation to purchase oil, natural gas or related commodities from us, we may be unable to sell such production to another customer on terms we consider acceptable, if at all, due to the geographic location of such production, the availability, proximity or capacity of gathering, processing, compression and transportation facilities or market or other factors and conditions.

The inability of our customers and other contractual counterparties to pay amounts owed to us and to otherwise satisfy their contractual obligations to us may materially and adversely affect our business, financial condition, results of operations and cash flows.

Environmental risks may adversely affect our business.

All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, state, tribal and municipal laws and regulations. These regulations include compliance obligations for air emissions, water quality, wastewater discharge, solid and hazardous waste disposal, and spill prevention, control and countermeasures, as well as for the protection of threatened or endangered species. In some cases, our operations are subject to federal requirements for performing or preparing environmental assessments, environmental impact studies and/or plans of development before commencing exploration and production activities. Legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. These requirements may negatively impact our operations and limit the quantity of natural gas and oil we produce and sell. Compliance with such legislation can also require significant expenditures and a breach may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner that we expect may result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require us to incur costs to remedy such discharge. The application of environmental laws to our business may cause us to curtail our production or increase the costs of our production, development or exploration activities.

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

We currently use hydraulic fracturing in our operations. Hydraulic fracturing typically involves the injection under pressure of water, sand and additives into rock formations in order to stimulate hydrocarbon production. Hydraulic fracturing using fluids other than diesel is currently exempt from regulation under the federal Safe Drinking Water Act (SDWA), but opponents of hydraulic fracturing have called for further study of the technique’s environmental effects and, in some cases, a moratorium on the use of the technique. Several proposals have been submitted to Congress that, if implemented, would subject all hydraulic fracturing to regulation under the SDWA. Eliminating this exemption could establish an additional level of regulation and permitting at the federal level that could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our cost of compliance and doing business. In addition, the EPA’s Office of Research and Development is conducting a scientific study to investigate the possible relationships between hydraulic fracturing and drinking water. The results of that study, which are expected to be available in draft during 2015 for peer review and public comment, could advance the development of additional regulations.

Even in the absence of new legislation, the EPA recently asserted the authority to regulate hydraulic fracturing involving the use of diesel additives under the SDWA’s Underground Injection Control Program (UIC Program), which regulates the underground injection of substances. On February 12, 2014, the EPA published UIC Program guidance for oil and natural gas hydraulic fracturing activities using diesel fuel. The guidance document is designed for use by employees of the EPA that draft the UIC permits and describes how regulations of Class II wells, which are those wells injecting fluids associated with oil and natural gas production activities, may be tailored to address the purported unique risks of diesel fuel injection during the hydraulic fracturing process. The EPA has encouraged state programs to review and consider use of the above mentioned guidance. To the extent that EPA’s new regulatory guidance is extended to our operations by permitting authorities, additional and significant compliance costs may arise that could materially affect our operations, cash flows, and financial position.

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

On May 16, 2013, the Department of Interior – Bureau of Land Management (BLM) released a revised proposed rule that, if adopted as drafted, would require companies operating on federal and Indian lands to (i) publicly disclose the chemicals used in the hydraulic fracturing process; (ii) confirm their wells meet certain construction standards and (iii) establish site plans to manage flowback water. The revised proposed rule was subject to a 90-day public comment period, which ended on August 23, 2013; the BLM has not yet issued a final rule. The Department of Energy, moreover, has developed its own recommendations for actions to lessen the environmental impact associated with hydraulic fracturing operations.

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

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

Our operations substantially depend on the availability of water. Restrictions on our ability to obtain, dispose of or recycle water may impact our ability to execute our drilling and development plans in a timely or cost-effective manner.

Water is an essential component of our drilling and hydraulic fracturing processes. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil, NGLs and natural gas, which could have an adverse effect on our business, financial condition and results of operations. Moreover, new environmental initiatives and regulations could include restrictions on disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of oil and gas. Compliance with environmental regulations and permit requirements for the withdrawal, storage and use of surface water or ground water necessary for hydraulic fracturing of our wells may increase our operating costs and cause delays, interruptions or cessation of our operations, the extent of which cannot be predicted, and all of which would have an adverse effect on our business, financial condition, results of operations and cash flows.

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

As of March 10, 2015, White Deer Energy L.P. (“White Deer Energy”) beneficially owned approximately 24.3% of our outstanding common stock on a fully diluted basis, consisting of 21,921,309 shares of our common stock, 472,452 underlying shares of our convertible notes and warrants to purchase 5,114,633 shares of our common stock. White Deer Energy owns 5,114,633 shares of our Series B Voting Preferred Stock, which have one vote per share and vote together with shares of our common stock. In addition, Ben Guill, a principal of White Deer Energy, is a member of our board of directors. As a result, White Deer Energy is able to exercise significant influence over matters requiring stockholder approval, including the election of directors, the adoption or amendment of provisions in our charter and bylaws, the approval of mergers and other significant corporate transactions. The interests of White Deer Energy with respect to matters potentially or actually involving or affecting us, such as future acquisitions, financings and other corporate opportunities, may conflict with the interests of our other stockholders.

If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud.

Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results could be harmed. We cannot be certain that our efforts to maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to continue to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet certain reporting obligations.

We will rely on technology to conduct our business and our technology could become ineffective or obsolete.

We rely on technology, including geographic and seismic analysis techniques and economic models, to develop our reserve estimates and to guide our exploration, development and production activities. We will be required to continually enhance and update our technology to maintain our efficacy and to avoid obsolescence. The costs of doing so may be substantial, and may be higher than the costs that we anticipated for technology maintenance and development. If we are unable to maintain the efficacy of our technology, our ability to manage our business and to compete may be impaired. Further, even if we are able to maintain technical effectiveness, our technology may not be the most efficient means of reaching our objectives, in which case we may incur higher operating costs than we would were our technology more efficient.

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Losses and liabilities from uninsured or underinsured drilling and operating activities could have a material adverse effect on our financial condition and operations.

We maintain several types of insurance to cover our operations, including worker’s compensation and comprehensive general liability. Amounts over base coverages are provided by primary and excess umbrella liability policies. We also expect to maintain operator’s extra expense coverage, which covers the control of drilling or producing wells as well as redrilling expenses and pollution coverage for wells out of control.

We may not be able to maintain adequate insurance in the future at rates we consider reasonable, or we could experience losses that are not insured or that exceed the maximum limits under our insurance policies. If a significant event that is not fully insured or indemnified occurs, it could materially and adversely affect our financial condition and results of operations.

We are subject to various governmental regulations and environmental risks that may cause us to incur substantial costs.

From time to time, in varying degrees, political developments and federal and state laws and regulations affect our operations. In particular, price controls, taxes, and other laws relating to the oil and natural gas industry, changes in these laws, and changes in administrative regulations have affected and in the future could affect oil and natural gas production, operations, and economics. We cannot predict how agencies or courts will interpret existing laws and regulations or the effect these adoptions and interpretations may have on our business or financial condition.

Our business is subject to laws and regulations promulgated by federal, state, and local authorities, including but not limited to the U.S. Congress, the EPA, the Bureau of Land Management, the Industrial Commission of North Dakota, and the Montana Board of Oil and Gas Conservation, relating to the exploration for, and the development, production, and marketing of, oil and natural gas, as well as safety matters. Legal requirements are frequently changed and subject to interpretation, and we are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations. We may be required to make significant expenditures to comply with governmental laws and regulations. The discharge of oil, natural gas, or other pollutants into the air, soil, or water may give rise to significant liabilities on our part to the government and third parties and may require us to incur substantial costs of remediation.

For example, regulators at both the federal and state levels have been taking a variety of actions to reduce air emissions from oil and gas operations. On April 17, 2012, the EPA approved final regulations under the U.S. Clean Air Act (CAA) that, among other things, require additional emissions controls for natural gas and natural gas liquids production, including New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (VOC) and a separate set of emission standards to address hazardous air pollutants frequently associated with such production activities. The final regulations require the reduction of VOC emissions from natural gas wells through the use of reduced emission completions or “green completions” on all hydraulically fractured wells constructed or refractured after January 1, 2015. These regulations also establish specific new requirements regarding emissions from dehydrators, storage tanks and other production equipment. The EPA later updated the standards in 2013 as well as 2014, and the Agency continues to reconsider portions of the rules. We continue to review these requirements and assess their potential impacts.

On July 1, 2014, moreover, the Industrial Commission of North Dakota, the State’s chief energy regulator, issued an order to reduce the volume of natural gas flared from oil wells in the Bakken / Three Forks formations. The State’s objectives are to capture 74% of the gas by the fourth quarter 2014, 77% by the first quarter 2015, 85% by the first quarter 2016, and 90%, with the potential for 95%, by the fourth quarter 2020. In addition, the Industrial Commission is requiring well operators to develop gas capture plans that describe how much natural gas is expected to be produced, how it will be delivered to a processor and where it will be processed. Production caps or penalties will be imposed on certain wells that cannot meet the capture goals. These capture requirements, and any similar future obligations in North Dakota or our other locations, may increase our operational costs or restrict our production.

On December 17, 2014, the EPA proposed to lower the existing 75 ppb national ambient air quality standard (NAAQS) for ozone under the CAA to a range within 65-70 ppb. The EPA is also taking public comment on whether the ozone NAAQS should be revised to as low as 60 ppb. A lowered ozone NAAQS in a range of 60-70 ppb could result in a significant expansion of ozone nonattainment areas across the United States, including areas in which we operate. Oil and natural gas operations in ozone nonattainment areas would likely be subject to increased regulatory burdens in the form of more stringent emission controls, emission offset requirements, and increased permitting delays and costs.

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The adoption of climate change legislation or regulations could result in increased operating costs, create delays in our obtaining air pollution permits for new or modified facilities, and result in reduced demand for the oil and natural gas we produce.

According to certain scientific studies, emissions of carbon dioxide, methane, nitrous oxide, and other gases commonly known as greenhouse gases (GHG) may be contributing to global warming of the earth’s atmosphere and to global climate change. In response to the scientific studies, legislative and regulatory initiatives have been underway to limit GHG emissions. The U.S. Supreme Court determined that GHG emissions fall within the definition of an “air pollutant,” and in response, the EPA promulgated an endangerment finding that paved the way for regulation of GHG emissions under the CAA. The EPA has also promulgated rules requiring owners or operators of certain petroleum and natural gas systems that emit 25,000 metric tons or more of GHG per year from a facility to report such emissions, and we are subject to this reporting requirement. In addition, the EPA promulgated rules that establish the emission thresholds that would identify major stationary sources of GHG subject to CAA permitting programs. As currently written and based on our current operations, we are not subject to federal GHG permitting requirements. Regulation of GHG emissions is new and highly controversial, and further regulatory, legislative, and judicial developments are likely to occur. Such developments may affect how these GHG initiatives will impact us. Further, apart from these developments, any judicial decisions that allow tort claims alleging property damage to proceed against GHG emissions sources may increase our litigation risk for such claims. Due to the uncertainties surrounding the regulation of and other risks associated with GHG emissions, we cannot predict the financial impact of related developments on us.

In connection with his climate action plan, President Obama released a Strategy to Reduce Methane Emissions in March 2014. Consistent with that strategy, the EPA has announced that it intends to issue a proposed rule in the summer of 2015 to set standards for methane and VOC emissions from new and modified oil and gas production sources and natural gas processing and transmission sources. The EPA intends to issue a final rule in 2016. As another prong of the President’s strategy, the BLM is expected to proposed standards in 2015 to reduce venting and flaring on public lands. The EPA and the BLM actions are part of a series of steps by the Obama Administration that are intended to result by 2025 in a 40-45% decrease in methane emissions from the oil and gas industry as compared to 2012 levels.

Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy. To the extent that our products are competing with higher GHG emitting energy sources, such as coal, our products could become more desirable in a market with more stringent limitations on GHG emissions. To the extent that our products are competing with lower GHG emitting energy sources, such as solar and wind, our products could become less desirable in the market with more stringent limitations on GHG emissions. We cannot predict with any certainty at this time how these possibilities may affect our operations. Any laws or regulations that may be adopted to restrict or reduce emissions of GHG could require us to incur increased operating costs and could have an adverse effect on demand for the oil and natural gas we produce, depending on the applicability to our operations and the refining, processing, and use of oil and natural gas.

Proposed legislation and regulation under consideration related to the transportation of crude oil via rail could increase our operating costs, delay our operations or otherwise alter the way we conduct our business.

The U.S. Department of Transportation (USDOT) has concluded that crude oil from the Bakken formation has a higher volatility than most other U.S. crude oil and thus is more ignitable and flammable. Those characteristics may pose an increased risk of accidents during handling. In response to recent train derailments involving oil from the Bakken that occurred in the United States and Canada in 2013, U.S. transportation regulators have implemented or are considering new rules to address the potential safety risks of transporting oil by rail. For example, on January 23, 2014, the NTSB issued a series of recommendations to address these potential safety risks, including (i) requiring railroads to engage in expanded hazardous material route planning to avoid populated and other sensitive areas, (ii) to audit the response capabilities of rail carriers that carry petroleum products, including an assessment of their ability to address discharges of the entire quantity of product carried on a train, and (iii) to audit shippers and rail carriers to ensure they are properly classifying hazardous materials in transportation and that they have adequate safety and security plans in place. Additionally, on February 25, 2014, the USDOT issued an emergency order requiring all persons, prior to offering petroleum crude oil into transportation, to ensure such product is properly tested and classed and to assure all shipments by rail of petroleum crude oil be handled as a Packing Group I or II hazardous material. The introduction of these or other regulations that result in new requirements addressing the type, design, specifications or construction of rail cars used to transport oil could result in severe transportation capacity constraints during the period in which new rail cars are retrofitted or constructed to meet these new specifications. Also, in February 2014, several rail carriers entered into a voluntary agreement with the USDOT (and some of its constituent agencies) to impose more stringent standards for shipments of oil. In December 2014, moreover, the Industrial Commission of North Dakota adopted conditioning standards that require operators to adjust the vapor pressure of Bakken crude oil.

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We do not currently own or operate rail transportation facilities or rail cars; however, we presently transport some of our oil production from the Bakken/Three Forks area to market by rail. The adoption of any regulations that impact the conditioning, testing or rail transportation of oil could increase our costs of doing business and limit our ability to transport and sell our oil at favorable prices at market centers throughout the United States, the consequences of which could have a material adverse effect on our financial condition, results of operations and cash flows.

Derivatives regulation included in current or proposed financial legislation and rulemaking could impact our ability to manage business and financial risks by restricting our use of derivative instruments as hedges against fluctuating commodity prices.

Historically, we have entered into a number of commodity derivative contracts in order to hedge a portion of our oil and natural gas production. In the US, the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act), which was passed by Congress and signed into law in July 2010, contains significant derivatives regulation, including a requirement that certain transactions be cleared on exchanges and a requirement to post collateral (commonly referred to as “margin”) for such transactions. The Dodd-Frank Act provides for an exception from these clearing and collateral requirements for commercial end-users, such as us, and it includes a number of defined terms that will be used in determining how this exception applies to particular derivative transactions and the parties to those transactions. As required by the Dodd-Frank Act, the Commodities Futures Trading Commission (CFTC) has promulgated numerous rules to define these terms.

In addition, it is possible that the CFTC, in conjunction with US prudential regulators, may mandate that financial counterparties entering into swap transactions with end-users must do so with credit support agreements in place, which could result in us being required to post collateral.

While we will not directly experience significant burdens from the changes in the regulation of derivatives, some of our counterparties may. If so, this could result in certain market participants deciding to curtail or cease their derivatives activities.

Item 1B.   Unresolved Staff Comments

None.

Item 2.   Properties

For a discussion of our properties, see Item 1. Business.

Item 3.   Legal Proceedings

From time to time, we are a party to litigation or other legal proceedings that we consider to be a part of the ordinary course of our business. We are not currently involved in any legal proceedings, nor are we a party to any pending or threatened claims, that could reasonably be expected to have a material adverse effect on our financial condition or results of operations.

Item 4.   Mine Safety Disclosures

Not applicable.

PART II

Item 5.   Market For Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities

Market Information

Our common stock is currently listed for trading on the NYSE MKT under the symbol “EOX.” From March 2, 2011 until September 4, 2012, our common stock was listed for trading on the NYSE MKT under the symbol “VOG.”

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The high and low sales prices per share of our common stock for each quarterly period within the two most recent fiscal years are indicated below, as reported on the NYSE MKT:

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Year Ended December 31, 2014
High	$	8.40	$	7.78	$	8.63	$	6.37
Low	$	6.34	$	6.00	$	6.15	$	0.83
Year Ended December 31, 2013
High	$	7.49	$	7.20	$	8.09	$	9.20
Low	$	5.17	$	5.81	$	6.36	$	6.54

Holders

As of March 10, 2015, we had 107,904,756 shares of our common stock outstanding, held by approximately 569 stockholders of record, which does not include the shareholders for whom shares are held in a nominee or street name. The number of record holders does not necessarily bear any relationship to the number of beneficial owners of our common stock.

Dividend Policy

We have never paid a cash dividend on our common stock, and the current policy of our board of directors is to retain any earnings to provide for our growth. The payment of cash dividends on our common stock in the future, if any, will be at the discretion of our board of directors and will depend on such factors as earnings levels, capital requirements, our overall financial condition and any other factors deemed relevant by our board of directors. Further, our revolving credit facility contains a number of significant covenants that, among other things, restrict or limit our ability to pay dividends or distributions on our capital stock.

Equity Compensation Plan Information

The following table summarizes information regarding the number of shares of our common stock that are available for issuance under our existing equity compensation plan as of December 31, 2014.

Plan Category	Number of Securities to be Issued upon Exercise of Outstanding Options, Warrants and Rights		Weighted Average Exercise Price of Outstanding Options, Warrants and Rights		Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a))
	(a)		(b)		(c)
Equity Compensation Plans Approved by Security Holders		1,090,819	$	7.65		4,796,935
Equity Compensation Plans Not Approved by Security Holders (1)		327,142		10.43		—
Total		1,417,961	$	8.29		4,796,935

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(1) In December 2009, we issued certain of our officers warrants to purchase a total of 223,293 shares of common stock exercisable at $6.86 per share pursuant to the terms of employment agreements. On April 21, 2010, we granted our outside directors stock options to purchase a total of 100,000 shares of common stock exercisable at $19.32 per share for serving as outside directors, 42,857 of which have been forfeited or have expired. On November 12, 2010, we granted an outside director stock options to purchase a total of 21,425 shares of common stock exercisable at $25.90 per share for serving as an outside director. In May 2011, we granted stock options to two employees to purchase a total of 14,286 and 7,143 shares of common stock exercisable at $21.14 and $24.85 per share, respectively, pursuant to the terms of their employment agreements. None of the officers, directors or employees had exercised any of the warrants or options as of December 31, 2014.

Issuer Purchases of Equity Securities

The following table summarizes repurchases of our common stock during the three months ended December 31, 2014.

Period	Total Number of Shares Purchased (1)		Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs
10/1/2014 – 10/31/2014		—		—		—		—
11/1/2014 – 11/30/2014		260,196	$	2.73		—		—
12/1/2014 – 12/31/2014		—		—		—		—
Total		260,196	$	2.73		—		—

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

Stock Performance Graph

The following graph shows our cumulative total shareholder return over the period from April 16, 2010, the date of our merger with ante4, Inc., to December 31, 2014, relative to the cumulative total returns of the Amex Oil Index and the Standard & Poor’s Composite 500 Index. The comparison assumes an investment of $100 (with reinvestment of all dividends) was made in our common stock on April 16, 2010, and in each of the indexes and its relative performance is tracked semi-annually through December 31, 2014.

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Emerald Oil, Inc.
Total Return Performance

The following table sets forth the total returns utilized to generate the foregoing graph.

	4/16/2010		12/31/2010		12/30/2011		12/31/2012		12/31/2013		12/31/2014
Emerald Oil, Inc.	$	100.00	$	385.71	$	183.57	$	53.47	$	78.16	$	12.24
Standard & Poor’s Composite 500 Index	$	100.00	$	105.50	$	105.49	$	119.63	$	155.05	$	172.71
Amex Oil Index	$	100.00	$	109.11	$	110.55	$	111.69	$	135.20	$	121.25

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Item 6.   Selected Financial Data

The financial statement information set forth below is derived from our balance sheets as of December 31, 2014, 2013, 2012, 2011 and 2010, and the related statements of operations, stockholders’ equity, and cash flows for the years ended December 31, 2014, 2013, 2012, 2011 and 2010 beginning on page F-1 of this report. On April 16, 2010, our predecessor, ante4, Inc., acquired Plains Energy Investments, Inc., at which time we began our present business operations.

	Year Ended December 31,
	2014			2013			2012 (1)			2011			2010
Statements of Income Information:
Revenues
Oil and Natural Gas Sales	$	101,168,591		$	53,981,040		$	28,129,985		$	8,426,129		$	942,840
Net Gains (Losses) on Commodity Derivatives		11,439,240			(2,656,535	)		(215,439	)		—			—
Total Revenues		112,607,831			51,324,505			27,914,546			8,426,129			942,840
Operating Expenses
Production Expenses		20,559,423			8,520,414			2,727,133			726,946			26,686
Production Taxes		11,010,300			5,702,521			2,955,015			717,440			102,743
General and Administrative Expenses		25,186,682			30,507,114			12,903,845			2,686,176			1,778,161
Depletion of Oil and Natural Gas Properties		34,798,218			17,310,059			12,770,718			3,546,466			547,844
Impairment of Oil and Natural Gas Properties		66,430,000			—			61,900,692			—			1,377,188
Depreciation and Amortization		389,551			144,492			53,818			30,831			2,929
Accretion of Discount on Asset Retirement Obligations		104,803			32,449			14,988			4,882			358
Acquisition Costs		409,712			—			—			—			—
Early Rig Termination Expense		4,286,906			—			—			—			—
Gain on Sale of Oil and Natural Gas Properties		—			(7,371,804	)		—			—			—
Total Expenses		163,175,595			54,845,245			93,326,209			7,712,741			3,835,909
Income (Loss) from Operations		(50,567,764	)		(3,520,740	)		(65,411,663	)		713,388			(2,893,069	)
Other Income (Expense), Net		(1,577,461	)		(7,362,155	)		3,115,564			(2,058,442			(1,310,260	)
Loss Before Income Taxes		(52,145,225	)		(10,882,895	)		(62,296,099	)		(1,345,054			(4,203,329	)
Income Tax Provision		—			—			—			—			65,240
Net Loss		(52,145,225	)		(10,882,895	)		(62,296,099	)		(1,345,054			(4,268,569	)
Less: Preferred Stock Dividends and Deemed Dividends		—			(20,279,197	)		—			—			—
Net Loss Available to Common Shareholders	$	(52,145,225	)	$	(31,162,092	)	$	(62,296,099	)	$	(1,345,054	)	$	(4,268,569	)
Net Loss Per Common Share – Basic and Diluted	$	(0.78	)	$	(0.75	)	$	(4.91	)	$	(0.17	)	$	(0.79	)
Weighted Average Shares Outstanding – Basic and Diluted		66,772,458			41,383,277			12,699,544			8,012,158			5,434,084
Balance Sheet Information:
Total Assets	$	689,059,876		$	429,887,663		$	173,886,362		$	104,839,421		$	48,495,426
Long-term Liabilities	$	231,370,975		$	16,451,464		$	23,796,074		$	15,116,119		$	10,522
Total Liabilities	$	367,166,752		$	94,568,554		$	63,592,277		$	25,697,480		$	15,774,602
Stockholders’ Equity	$	321,888,124		$	335,314,109		$	110,294,085		$	79,141,941		$	32,720,824
Statement of Cash Flow Information:
Net cash provided by (used for) operating activities	$	56,830,883		$	6,190,440		$	(4,289,767	)	$	(153,156	)	$	(1,165,634	)
Net cash used for investing activities	$	(429,268,096	)	$	(75,000,538	)	$	(66,452,633	)	$	(43,508,278	)	$	(3,745,202	)
Net cash provided by financing activities	$	240,571,005		$	202,873,157		$	58,427,978		$	46,230,181		$	15,578,094

(1) We acquired Emerald Oil North America, Inc. from Emerald Oil & Gas NL on July 26, 2012. Our consolidated financial and operating results reflect the operations of the acquisition from the closing date (July 26, 2012) through December 31, 2012.

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Item 7.   Management’s Discussion and Analysis of Financial Condition and Results of Operations

This Item 7 contains “forward-looking” statements. See “Cautionary Statement Concerning Forward-Looking Statements” at the beginning of this report. The following discussion should be read in conjunction with Item 6. Selected Financial Data and Item 8. Financial Statements and Supplementary Data appearing elsewhere in this report. On July 26, 2012, we completed the acquisition of Emerald Oil North America, Inc., formerly Emerald Oil, Inc. (“Emerald Oil North America”), from Emerald Oil & Gas NL. Accordingly, this document includes Emerald Oil North America, its consolidated subsidiaries and the operations of the combined businesses from the closing date (July 26, 2012).

Overview and Outlook

We are an oil and natural gas exploration and production company. Our properties are located in North Dakota and Montana. Our corporate strategy is to build stockholder value through the development and acquisition of oil and natural gas assets that exhibit economically producible hydrocarbons.

As of December 31, 2014, we controlled the rights to mineral leases covering approximately 122,000 net acres. Our business currently focuses on the development of our properties in North Dakota and Montana. Our goals are to continue to explore for and develop hydrocarbons within the mineral leases we control as well as continue to expand our acreage position should strategic opportunities present themselves. In order to accomplish our objectives we will need to achieve the following:

• continue to develop our substantial inventory of high quality core Bakken and Three Forks acreage with results consistent with or superior to the results we have achieved to date;

• retain and attract talented personnel;

• continue to be a low-cost producer of hydrocarbons to maximize returns in all commodity pricing environments; and

• continue to manage our financial obligations to access the appropriate capital needed to develop our position of primarily undrilled acreage.

Our financial results depend upon many factors, but are largely driven by the volume of our oil and natural gas production and the price that we receive for that production. Our production volumes will decline as reserves are depleted unless we expend capital in successful development and exploration activities or acquire properties with existing production. The amount we realize for our production depends predominantly upon commodity prices and our related commodity price hedging activities, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. Accordingly, finding and developing oil and natural gas reserves at economical costs is critical to our long-term success.

For the twelve months ended December 31, 2014 we incurred capital expenditures for drilling and completions of approximately $298.6 million, excluding acquisitions. 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. The significant decrease in planned capital spending for 2015, as compared to actual 2014 drilling and completion capital expenditures, is in response to the significant decrease in crude oil prices over the latter half of 2014 and our expectations that prices may not recover in the near term. Our 2015 drilling and completion budget contemplates one variable operated rig. Our drilling and completion budget for 2015 is based on our current view of market conditions and current business plans, and is subject to change.

We expect to fund our 2015 capital program through existing cash on hand, our expected cash flows from operations, proceeds from the equity offering completed in February 2015 and borrowing capacity expected to be available under our revolving credit facility. We strive to maintain financial flexibility and may access capital markets as necessary to maintain substantial borrowing capacity under our revolving credit facility, facilitate drilling on our large undeveloped acreage position and permit us to selectively expand our acreage position. In the event our cash flows are materially less than anticipated and other sources of capital we historically have utilized are not available on acceptable terms, we may further curtail our capital spending.

Oil and natural gas prices are inherently volatile and, as mentioned above, decreased significantly over the latter half of 2014. Sustained lower commodity prices will likely have a material impact upon our full cost ceiling test calculation. The ceiling calculation dictates that we use the unweighted arithmetic average price of crude oil and natural gas as of the first day of each month for the 12-month period ending at the balance sheet date. For the year ended December 31, 2014, those prices were $94.99 per Bbl for oil and $4.35 per MMBtu for natural gas, while the unweighted arithmetic average price of crude oil and natural as of the first day of each month for the 12-month period through March 2015 were $82.72 per Bbl and $3.68 per MMBtu for natural gas. If commodity prices remain at decreased levels, the average prices used in the ceiling calculation will decline and will likely cause potential 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.

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Acquisitions and Divestitures

In September 2014, we acquired approximately 30,500 net acres located in McKenzie, Billings and Dunn Counties of North Dakota from an unrelated third party. The total consideration paid was approximately $71.2 million in cash and the assignment of approximately 4,300 net acres located in Williams County, North Dakota. Net daily production from the acquired acreage was approximately 400 Boe/day as of May 1, 2014, the effective date of the transaction. The acquisition increased our interest in 12 existing operated designated spacing units (“DSUs”) in our Low Rider area, added six potentially operated DSUs in our Low Rider area, increased our working interest in one existing operated DSU in our Lewis & Clark area and added 17 potentially operated DSUs in our Lewis & Clark area, while divesting our acreage position in our Easy Rider area. We did not have any production associated with the approximate 4,300 net acres assigned as part of the purchase price consideration.

In February 2014, we acquired approximately 19,500 net acres located in Williams and McKenzie Counties, North Dakota from an unrelated third party for approximately $69.2 million in cash. Net daily production from the acreage was approximately 300 Boe/day as of January 1, 2014, the effective date of the transaction. The acquisition added 15 potentially operated DSUs in our Low Rider prospect and two potentially operated DSUs in our Lewis & Clark prospect.

In February 2014, we acquired in two separate transactions approximately 5,900 net acres of undeveloped leasehold located in McKenzie and Billings Counties, North Dakota from an unrelated third party for approximately $10.3 million in cash. The acquisitions added one and two potentially operated DSUs in our Low Rider and Lewis & Clark prospect areas, respectively, and increased our working interest in four existing DSUs.

2014 Capital Development Plan

In 2014, we incurred total capital well costs of approximately $298.6 million, excluding acquisitions. In 2014, our operated well expenditures totaled $276.2 million to drill 28.6 net wells and complete 24.2 net wells, compared to our budgeted operated well expenditures of $250.0 million. Our non-operated well expenditures totaled $22.4 million during the year to drill 3.8 net wells and complete 4.4 net wells. We exceeded our 2014 capital budget by $48.6 million because we drilled more net wells compared to our original operated development budget, the timing of well completions was faster than projected and the completions costs were higher than expected. Also, we deployed more capital into our non-operated properties due to attractive non-operated well economics in the first three quarters of the year.

In 2014, we initially budgeted approximately $150.0 million to increase our working interests in our core operated areas along with continuing to grow our overall operated acreage position in the Williston Basin. Following the acquisition of approximately 30,500 net acres in North Dakota in September 2014 as described under Item 7. - Acreage Acquisitions and Divestitures above, we increased our 2014 land acquisition budget to $200 million. For the year ended December 31, 2014, we incurred $175.3 million toward our revised $200 million land acquisition budget, as we slowed our acquisition activity in the fourth quarter.

The Low Rider area, which is our core operated area, consists of approximately 72,000 net acres that are primarily located in McKenzie County, North Dakota. Our average working interest in our operated wells in the Low Rider area as of December 31, 2014 was approximately 76%, and we continue to work toward increasing our average working interest in the area. Entering the fourth quarter of 2014, we were running a three-rig horizontal development program, consisting of two rigs in the Low Rider area and one rig in the Pronghorn Sand area.. In December 2014, management decided to immediately reduce our 2015 development program given the declining commodity price environment, and we released two of our three operated drilling rigs.

Our future financial results will depend primarily on: (i) the ability to fully implement our exploration and development program, which is dependent on the availability of capital resources; (ii) the ability to continue to source and evaluate potential projects; (iii) the ability to discover commercial quantities of oil and natural gas; and (iv) the market price for oil and natural gas. There can be no assurance that we will be successful in any of these respects, that the prices of oil and natural gas prevailing at the time of production will be at a level allowing for profitable production, or that we will be able to obtain additional funding, if necessary. See Item 1A. Risk Factors.

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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. We expect to fund our 2015 capital program through existing cash on hand, our expected cash flows from operations, proceeds from the equity offering completed in February 2015, and expected borrowing capacity under our revolving credit facility. Our 2015 production and capital expenditure estimates are currently based upon a variable one-rig drilling program. We plan to drill and complete five wells during 2015. Four of these wells are expected to be spud before the end of the second quarter of 2015, and the fifth well is expected to be spud in the second half of 2015. Because we have a backlog of drilling permits, we may add additional wells to our 2015 development schedule if commodity prices improve. The one rig will be held on standby during 2015 while it is not drilling. In Low Rider, we have a current inventory of nine wells that have been drilled and remain to be completed over the next three months. Under the variable one rig program we expect to move into a free cash flow generative position in the second quarter of 2015 in the current oil strip environment.

Liquidity and Capital Resources

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

The following table summarizes total current assets, total current liabilities and working capital at December 31, 2014:

Current assets	$	57,748,652
Current liabilities		135,795,777
Working capital	$	(78,047,125	)

Equity Offering

In February 2015, we completed a public offering of 27,159,107 shares of common stock at a price of $1.12 per share for total net proceeds of approximately $29.4 million, including the underwriter’s election to exercise a portion of its over-allotment portion.

Convertible Note Offering

In March 2014, we completed a private placement of $172.5 million in aggregate principal amount of 2.0% Convertible Senior Notes (the “Convertible Notes”), and entered into an indenture, or the Indenture governing the Convertible Notes, with U.S. Bank National Association as trustee. The Convertible Notes accrue interest at a rate of 2.00% per year, payable semiannually in arrears on April 1 and October 1 of each year, beginning on October 1, 2014. The Convertible Notes mature on April 1, 2019. The Convertible Notes are our unsecured senior obligations and are equal in right of payment to our existing and future senior indebtedness. The Convertible Notes have been classified as long-term debt as of December 31, 2014.

The net proceeds from the offering were $166.9 million, after deducting the initial purchasers’ discounts and commissions and offering expenses. A portion of the net proceeds from the Convertible Notes were used to repay all of the outstanding borrowings under our revolving credit facility, and the remainder of the net proceeds have been and will be used for general corporate purposes, including funding a portion of our drilling and development program and potential acquisitions.

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(2). The Convertible Notes were resold by the initial purchasers to qualified institutional buyers in reliance on Rule 144A under the Securities Act. In accordance with the Indenture and no later than April 3, 2015, we will cooperate in taking steps to remove all legends and/or restrictions on the right to sell the Convertible Notes under Rule 144 of the Exchange Act.

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Holders may convert their Convertible Notes at their option at any time prior to the close of business on the business day immediately preceding the maturity date of the Convertible Notes. The conversion rate for the Convertible Notes is initially 113.9601 shares of our common stock per $1,000 principal amount of Convertible Notes (which represents an initial conversion price of approximately $8.78 per share of our 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 we undergo a Fundamental Change (as defined in the Indenture), subject to certain conditions, the holder of the Convertible Notes will have the option to require us 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. We may not redeem the Convertible Notes prior to their maturity, and no sinking fund is provided for the Convertible Notes.

We do not intend to file a shelf registration statement for resale of the Convertible Notes or the shares of our common stock issuable upon conversion of the Convertible Notes. We 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 our common stock issued upon conversion of the Convertible Notes, if any, pursuant to an exemption from the registration requirements of the Securities Act and other applicable securities laws.

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

In December 2014, we issued 10,721,824 shares of common stock in exchange for $21,000,000 of Convertible Notes. We had previously reserved for issuance 2,393,162 shares of common stock for these Convertible Notes upon conversion under the original terms of the Indenture. As a result, we recognized $10,438,080 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 exchanged Convertible Notes.

Credit Facility

On November 20, 2012, we entered into a senior secured revolving credit facility (the “Credit Facility”) with Wells Fargo Bank, N.A., as administrative agent (“Wells Fargo”), and the lenders party thereto. The Credit Facility is a senior secured reserve-based revolving credit facility with a maximum commitment of $400 million. As of December 31, 2014, we had drawn $75.0 million of the $250 million borrowing base under the Credit Facility.

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

The annual interest cost under the Credit Facility, which is dependent upon the percentage of the borrowing base utilized, is, at 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 December 31, 2014, the annual interest rate on the Credit Facility was 3.16%.

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 December 31, 2014, 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 our guarantors, including a pledge of their ownership in their respective subsidiaries.

The Credit Facility contains customary covenants that include, among other things: limitations on our ability to incur or guarantee additional indebtedness; create liens; pay dividends on or repurchase stock; make certain types of investments; enter into transactions with affiliates; and sell assets or merge with other companies. The Credit Facility also requires compliance with certain financial covenants, including, (a) a ratio of current assets to current liabilities of at least 1.00 to 1.00, (b) a maximum ratio of total debt to EBITDA for the preceding four fiscal quarters of no more than 4.00 to 1.00. For any fiscal quarter ending in calendar year 2014, total debt is reduced by cash equivalents less $10,000,000 for purposes of calculating the total debt to EBITDA ratio. We were in compliance with all covenants under the Credit Facility as of December 31, 2014.

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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.

Satisfaction of Our Cash Obligations for the Next Twelve Months

We project we will have sufficient capital to accomplish our development plan and forecasted general and administrative expenses for the next twelve months. In December 2014, management decided to reduce the 2015 development program given the current commodity price environment. We released two of our three operated rigs in December 2014. Our 2015 production and capital expenditure estimates are now based upon a variable one-rig drilling program. Under the variable one rig program, Emerald will move into a free cash flow generative position in the second quarter of 2015 in the current oil strip environment. Our projections are based on cash on hand, our expected cash flow from operations, proceeds from our February 2015 equity offering and expected borrowing capacity under our Credit Facility. However, we may scale back our development plan should our projections of cash flow and borrowing capacity fall short of expectations or commodity prices fall substantially. We may also choose to access the equity or debt capital markets to fund acreage acquisitions and/or accelerated drilling at the discretion of management, depending on prevailing market conditions. We will evaluate any potential opportunities for acquisitions as they arise and meet our strategic objectives. We believe we are in a position to take advantage of any appropriately priced acquisition opportunities that may arise. However, there can be no assurance that any additional capital will be available to us on favorable terms or at all. See Item IA. Risk Factors – We may be unable to obtain additional capital that we require to implement our business plan, which could restrict our ability to grow.

Our prospects must be considered in light of the risks, particularly companies in the oil and natural gas exploration industry. Such risks include, but are not limited to, an evolving business model and the management of growth. To address these risks we must, among other things, implement and successfully execute our business and marketing strategy, respond to competitive developments, and attract, retain and motivate qualified personnel. There can be no assurance that we will be successful in addressing such risks, and the failure to do so can have a material adverse effect on our business prospects, financial condition and results of operations.

Effects of Inflation and Pricing

The oil and natural gas industry is cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry put extreme pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do all associated costs. Conversely, in a period of declining prices, associated cost declines are likely to lag and may not adjust downward in proportion. Material changes in prices also impact our current revenue stream, estimates of future reserves, borrowing base calculations 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 Item IA. Risk Factors – Prices and markets for oil and natural gas are unpredictable and tend to fluctuate significantly, which could reduce profitability, growth and the value of our business.

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 and collars. See Critical Accounting Policies and Estimates – Derivative Instruments, below, for our methodology for valuing commodity derivative instruments.

Cash and Cash Equivalents

Our total cash resources as of December 31, 2014 were $12,389,230, compared to $144,255,438 as of December 31, 2013. The decrease in our cash balance was primarily attributable to acquisitions and development of oil and natural gas properties, offset by the Convertible Notes offering completed in March 2014 and borrowings under our Credit Facility.

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Net Cash Provided By Operating Activities

Net cash provided by operating activities was $56,830,883 for the year ended December 31, 2014 compared to $6,190,440 for the year ended December 31, 2013. The change in the net cash provided by operating activities is primarily attributable to higher production revenue during 2014, offset by higher production expenses and other operating expenses.

Net Cash Used For Investment Activities

Net cash used in investment activities was $429,268,096 for the year ended December 31, 2014 compared to $75,000,538 for the year ended December 31, 2013. The change in net cash used in investment activities is primarily attributable to increased purchase and development of oil and natural gas properties in the Williston Basin, offset by net proceeds from the sale of oil and natural gas properties of approximately $36.2 million.

Net Cash Provided By Financing Activities

Net cash provided by financing activities was $240,571,005 for the year ended December 31, 2014 compared to $202,873,157 for the year ended December 31, 2013. The change in net cash provided by financing activities for the year ended December 31, 2014 is attributable to proceeds from the Convertible Note offering completed in March 2014, along with advances on the Credit Facility.

Contractual Obligations and Commitments

As of December 31, 2014, we had $75 million drawn on our $250 million Credit Facility. See — Liquidity and Capital Resources — Credit Facility. We have no material capital lease obligations, operating lease obligations or purchase obligations requiring future payments other than our Denver, Colorado office lease that expires on October 31, 2019. The following table illustrates our contractual obligations as of December 31, 2014.

	Payment due by period
Contractual Obligations	Total		Less than 1 year		2 – 3 years		4 – 5 years		More than 5 years
Office Leases (1)	$	2,320,441	$	464,088	$	953,801	$	902,552	$	—
Drilling Rig Obligations (2)		3,700,000		3,700,000		—		—		—
Revolving Credit Facility (3)		84,494,000		2,373,500		4,747,000		77,373,500		—
Senior Convertible Notes (4)		165,240,000		3,135,000		6,060,000		156,045,000		—
Automobile Leases (5)		2,970		2,970		—		—		—
Office Equipment (6)		53,607		22,500		31,107		—		—
	$	255,811,018	$	9,698,058	$	11,791,908	$	234,321,052	$	—

(1) Our Denver, Colorado office lease commenced on December 15, 2012 and, as amended, has a term of 66 months, expiring in October 2019.

(2) As of December 31, 2014, we are subject to commitments on one operated drilling rig, which expires in 2015. In the event of early termination under the contract, we would be obligated to pay an aggregate amount of approximately $3.7 million as of December 31, 2014 as required under the terms of the contract.

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(3) Calculated based on our December 31, 2014 outstanding borrowings under our Credit Facility of $75.0 million and assumes no principal repayment until the maturity date on September 30, 2018. Interest on the Credit Facility is payable at one of the following two variable rates: the alternate base rate for ABR loans or the adjusted LIBO rate for Eurodollar loans, as selected by us, plus an additional percentage that can vary on a daily basis and is based on the daily unused portion of the facility. This additional percentage is referred to as the “Applicable Margin” and varies depending on the type of loan. The Applicable Margin for the ABR loans is a sliding scale of 0.75% to 1.75%, depending on borrowing base usage. The Applicable Margin on the adjusted LIBO rate is a sliding scale of 1.75% to 2.75%, depending on borrowing base usage. Additionally, the Credit Facility provides for a commitment fee of 0.375% to 0.50%, depending on borrowing base usage. Cash interest expense on the Credit Facility is estimated assuming no principal repayment until the maturity date and a fixed interest rate of 3.16% (our effective interest rate including the commitment fee on the Credit Facility as of December 31, 2014). For further discussion regarding the terms of the Credit Facility refer to Note 8 – Revolving Credit Facility under Item 8 in this Annual Report.

(4) Calculated based on our December 31, 2014 outstanding aggregate principal amount of $151.5 million outstanding on under our Convertible Notes due April 1, 2019 at a fixed interest rate of 2.0%. Interest is payable semiannually in arrears on April 1 and October 1 of each year through the maturity date. For further details regarding the terms of the Convertible Notes, refer to Note 9 – Convertible Notes under Item 8 in this Annual Report.

(5) In April 2013, we entered into an automobile lease for a vehicle utilized by our drilling operation employees in North Dakota, which expires in March 2015.

(6) In October 2013 and December 2013, we entered into various leases for office equipment, which expire in December 2016 and February 2017, respectively.

The above contractual obligations schedule does not include anticipated estimated amounts expected to be incurred in the future associated with the abandonment of our oil and natural gas properties or settlement of derivative contracts, as we cannot determine with accuracy the timing of such payments. For further discussion regarding our estimated future costs associated with the abandonment of our oil and natural gas properties and derivative contracts please refer to Note 10 - Asset Retirement Obligations and Note 14 – Derivative Instruments and Price Risk Management under Item 8 in this Annual Report.

As is customary in the oil and natural gas industry, we may at times have commitments in place to reserve or earn certain acreage positions or wells. If we do not meet such commitments, the acreage positions or wells may be lost.

Operating Results

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.

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	Year Ended December 31,
	2014		2013			2012
Net Oil and Natural Gas Revenues:
Oil	$	98,532,131	$	52,609,790		$	27,264,526
Natural Gas and Other Liquids		2,636,460		1,371,250			865,459
Total Oil and Natural Gas Sales		101,168,591		53,981,040			28,129,985
Net Gains (Losses) on Commodity Derivatives		11,439,240		(2,656,535	)		(215,439	)
Total Revenues	$	112,607,831	$	51,324,505		$	27,914,546
Oil Derivative Net Cash Settlements Received (Paid)	$	5,542,110	$	(1,984,778	)	$	(34,191	)
Net Production:
Oil (Bbl)		1,238,807		580,797			320,147
Natural Gas and Other Liquids (Mcf)		338,536		211,608			129,648
Barrel of Oil Equivalent (Boe)		1,295,230		616,065			341,755
Average Sales Prices:
Oil (per Bbl)	$	79.54	$	90.58		$	85.16
Effect of Settled Oil Derivatives on Average Price (per Bbl)		4.47		(3.42	)		(0.11	)
Oil Net of Settled Derivatives (per Bbl)	$	84.01	$	87.16		$	85.05
Natural Gas and Other Liquids (per Mcf)	$	7.79	$	6.48		$	6.68
Barrel of Oil Equivalent with Net Cash Settlements Paid on Commodity Derivatives (per Boe)	$	82.39	$	84.40		$	82.21

Production costs incurred, presented on a per Boe basis, for the years ended December 31, 2014, 2013 and 2012 are summarized in the following table:

	Year Ended December 31,
	2014		2013		2012
Costs and Expenses Per Boe of Production :
Lease Operating Expenses	$	12.00	$	13.22	$	7.75
Workover Expenses		3.88		0.61		0.23
Total Production Expenses		15.88		13.83		7.98
Production Taxes		8.50		9.26		8.65
G&A Expenses (Excluding Share-Based Compensation)		10.60		28.60		16.34
Shared-Based Compensation		8.85		20.92		21.42
Depletion of Oil and Natural Gas Properties		26.87		28.10		37.37
Impairment of Oil and Natural Gas Properties		51.29		—		181.13
Depreciation and Amortization		0.30		0.23		0.16
Accretion of Discount on Asset Retirement Obligation		0.08		0.05		0.04

Year Ended December 31, 2014 Compared to the Year Ended December 31, 2013

Revenues

Revenues from sales of oil and natural gas were $101.2 million in 2014 compared to $54.0 million in 2013. For 2014, our total production volumes on a Boe basis increased 110.24% as compared to 2013. Production primarily increased due to the addition of 24.19 net productive operated Bakken/Three Forks wells in 2014. During 2014, we realized an $84.01 average price per Bbl of oil (including settled derivatives) compared to an $87.16 average price per Bbl of oil during 2013.

Net Gains and Losses on Commodity Derivatives

Net gains on commodity derivatives were $11,439,240 in 2014 compared to a loss of $2,656,535 in 2013. Net cash settlements received on commodity derivatives were $5,542,110 in 2014 compared net cash settlements paid of $1,984,778 in 2013. 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 December 31, 2014 and 2013, all of our derivative contracts were recorded at their fair value, which was a net asset of $5,044,125 and a net liability of $853,005, respectively.

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Production Expenses

Production expenses were $20,559,423 in 2014 compared to $8,520,414 in 2013. Workover expenses totaling $5,019,104 were incurred in 2014 compared to $374,519 in 2013. A portion of the increase in workover expense was attributable to producing properties acquired during 2013 and 2014. On a per unit basis, production expenses decreased from $13.22 per Boe in 2013 to $12.00 per Boe in 2014 when excluding workover costs. We experience increases in production expenses as we add new wells and maintain production from existing properties. The use of power generators and associated fuel costs, the disposal of produced water and pump repairs and replacement are large cost drivers in our Williston Basin wells.

Production Taxes

Production taxes were $11,010,300 in 2014 compared to $5,702,521 in 2013. We pay production taxes based on realized oil and natural gas sales. Our production tax rates were 10.88% in 2014 compared to 10.56% in 2013. Certain portions of our production occurs in North Dakota and Montana jurisdictions that have lower initial tax rates for an established period of time or until an established threshold of production is exceeded, after which the tax rates are increased to the standard tax rate of 11.5%. The 2014 average production tax rate was higher than 2013 due to expirations of production tax holidays during the year.

General and Administrative Expense

General and administrative expenses were $25,186,682 in 2014 compared to $30,507,114 in 2013. The 2014 decrease of $5,320,432 when compared to 2013 is primarily due to lower employee compensation and employee-related expenses. Employee compensation and employee-related expenses decreased on a year-over-year basis in 2014 compared to 2013 by $6,158,045 due to lower executive compensation, offset by an increase of $650,307 related to professional and legal expense due to increased business development and significant current year acquisitions, and an increase of $188,118 in software expenses due to increased infrastructure development. Share-based compensation expenses are included in the employee compensation and related expenses, totaling $11,459,431 in 2014 compared to $12,885,236 in 2013. Approximately $919,633 and $2,755,402 of the share-based compensation expense during the year ended December 31, 2014 and 2013, respectively, related to the modification and accelerated vesting of equity grants associated with severance to prior officers of the Company.

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 $34,798,218 in 2014 compared to $17,310,059 in 2013. On a per-unit basis, depletion expense was $26.87 per Boe in 2014 compared to $28.10 per Boe in 2013. Our depletion expense is based on the capitalized costs related to properties having proved reserves, plus the estimated future development costs and asset retirement costs which are depleted and amortized on the unit-of-production method based on the estimated gross proved reserves determined by our independent petroleum engineers. This increase in depletion expense in 2014 was due primarily to the addition of 24.19 net productive operated Bakken/Three Forks wells in 2014.

Impairment of Oil and Natural Gas Properties

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

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We recognized $66,430,000 of impairment expense in 2014 compared to $0 in 2013. Included in the full cost pool at December 31, 2014 was $71.2 million of costs related to acquisitions made in 2014 based on higher price decks than the SEC price deck used at December 31, 2014. Further, the 12-month average price is $7.12 lower than the 12-month average price used at December 31, 2013.

If commodity prices remain at decreased levels, the 12-month average price used in the ceiling calculation will decline and will likely cause potential 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.

Other Income (Expense), Net

Other expense, net was $1,577,461 for the year ended December 31, 2014 compared to $7,362,155 for the year ended December 31, 2013. We recognized a gain of $13,504,000 on the warrant liability during 2014, compared to a loss of $7,077,000 in 2013. Our warrant liability is accounted for using the mark-to-market accounting method whereby gains and losses from changes in the fair value of derivative instruments are recognized immediately into earnings. Interest expense was $4,675,475 for the year ended December 31, 2014, compared to $287,934 for the year ended December 31, 2013. The increase in interest expense primarily relates to interest expense incurred on the Convertible Notes issued in March 2014. In December 2014, we issued 10,721,824 shares of common stock in exchange for $21,000,000 of Convertible Notes. As a result of the issuance, we recognized $10,438,080 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 acquired Convertible Notes.

Net Income (Loss) Attributable to Common Stockholders

We had a net loss attributable to common stockholders of $52,145,225 in 2014 compared to a net loss of $31,162,092 in 2013 (representing $(0.78) and $(0.75) per share, respectively). The change in net loss attributable to common stockholders in our period-over-period results was driven by increased revenue and production from our oil and natural gas properties, lower general and administrative expenses and a gain on our warrant liability, offset by an impairment expense on oil and natural gas properties, debt conversion expense on our Convertible Notes and increased interest expense.

Year Ended December 31, 2013 Compared to the Year Ended December 31, 2012

Revenues

Revenues from sales of oil and natural gas were $54.0 million in 2013 compared to $28.1 million in 2012. For 2013, our total production volumes on a Boe basis increased 80.27% as compared to 2012. Production primarily increased due to the addition of 10.58 net productive operated Bakken/Three Forks wells in 2013, offset by the sale of 9.13 net productive non-operated wells in the Williston Basin in 2013. During 2013, we realized an $87.16 average price per Bbl of oil (including settled derivatives) compared to an $85.05 average price per Bbl of oil during 2012.

Net Losses on Commodity Derivatives

Net losses on commodity derivatives were $2,656,535 in 2013 compared to $215,439 in 2012. Net cash settlements paid on commodity derivatives were $1,984,778 in 2013 compared to $34,191 in 2012. Our derivatives are not designated for hedge accounting and are accounted for using the mark-to-market accounting method whereby gains and losses from changes in the fair value of derivative instruments are recognized immediately into earnings.  Mark-to-market accounting treatment creates volatility in our revenues as 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 December 31, 2013 and 2012, all of our derivative contracts were recorded at their fair value, which was a net liability of $853,005 and $181,248, respectively.

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Production Expenses

Production expenses were $8,520,414 in 2013 compared to $2,727,133 in 2012. We experience increases in operating expenses as we add new wells and maintain production from existing properties. On a per unit basis, production expenses increased from $7.98 per Boe sold in 2012 to $13.83 per Boe in 2013. This increase was primarily due to the costs associated with operating an increased number of producing wells and associated produced fluid volumes as a result of our 2013 well completions. Increased costs primarily related to workovers, chemical treatments, equipment rental and fresh water injections, which have improved operational performance and reduced downtime in our wells. The disposal of produced water is also a large cost driver in Williston Basin wells.

Production Taxes

Production taxes were $5,702,521 in 2013 compared to $2,955,015 in 2012. We pay production taxes based on realized oil and natural gas sales. Our production tax rates were 10.56% in 2013 compared to 10.50% in 2012. Certain portions of our production occurs 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 2013 average production tax rate was higher than 2012 due to expirations of production tax holidays during the year.

General and Administrative Expense

General and administrative expenses were $30,507,114 in 2013 compared to $12,903,845 in 2012. The 2013 increase of $17,603,269 when compared to 2012 is due to our change in corporate strategy to add operating capabilities to develop our own operated wells in the Williston Basin and increases in personnel and infrastructure. This strategic change allows us the opportunity to significantly grow production by using industry best practices and to control well design and capital expenditures to maximize our return on capital. Specifically, 2013 expense increased on a year-over-year basis compared to 2012 due to an increase of $14,741,644 in employee compensation and related expense, an increase of $1,736,078 related to professional and legal expense, and an increase of $1,231,784 in other general and administrative expenses such as rent, insurance, travel and office expenses. Share-based compensation expenses are included in the employee compensation and related expenses, totaling $12,885,236 in 2013 compared to $7,318,690 in 2012. Approximately $2,755,402 of the share-based compensation expense during the year ended December 31, 2013 related to the modification and accelerated vesting of equity grants associated with severance to a prior officer of the Company.

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 $17,310,059 in 2013 compared to $12,770,718 in 2012. On a per-unit basis, depletion expense was $28.10 per Boe in 2013 compared to $37.37 per Boe in 2012. Our depletion expense is based on the capitalized costs related to properties having proved reserves, plus the estimated future development costs and asset retirement costs which are depleted and amortized on the unit-of-production method based on the estimated gross proved reserves determined by our independent petroleum engineers. This increase in depletion expense in 2013 was due primarily to the addition of 10.58 net productive operated Bakken/Three Forks wells in 2013, offset by the sale of 9.13 net productive non-operated wells in the Williston Basin in 2013.

Impairment of Oil and Natural Gas Properties

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

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We recognized no impairment expense in 2013 compared to $61,900,692 in 2012. Included in the full cost pool at December 31, 2012 was $23.8 million of costs related to our Niobrara development program in the DJ Basin of Colorado that we deemed uneconomic, $11.5 million of costs associated with the write-down of the Sand Wash Basin to fair market value reflective of the sale in January 2013 and $3.6 million of expiring leases in North Dakota, which we deemed uneconomic to pursue.  Combined, these items have added $38.9 million of costs to the full cost pool in 2012 without contributing reserves and discounted future net revenues to increase the ceiling.  The remaining $23.0 million impairment charge in 2012 was a result of reclassifying proven undeveloped reserves into probable reserves to better reflect our current development program. We have moved away from our previous business model that focused on participating in non-operated wells developed by others to our current operated program over which we have control of the timing of well development and design of our wells. Going forward, we plan to participate in significantly fewer non-operated wells and grow reserves through our operated well development program.

Gain on Sale of Oil and Natural Gas Properties, net

We recognized a gain of $7,371,804 relating to the sale of oil and natural gas properties for the year ended December 31, 2013. We sold our interest in 26,579 non-operated net acres located in the Williston Basin to an unrelated third party for a total sales price of approximately $111.0 million in cash, including sales price adjustments for development costs and production revenue and operating expenses during the effective period and subject to certain post-closing adjustments. $11.0 million of the sales price was held in escrow upon finalization of standard due diligence procedures. On February 21, 2014 $8.6 million was released to us, with the remaining $2.4 million returned to the buyer for purchase price adjustments during the due diligence period. The acreage was associated with non-operated working interests in Bakken and Three Forks wells. Under the full cost method of accounting for oil and natural gas operations, sales of oil and natural gas properties, whether or not being amortized, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to the full cost pool. The sale represented greater than 25% of our proved reserves of oil and natural gas attributable to the cost center at the time of the sale. As a result, there was a significant alteration in the relationship between capitalized costs and proved reserves of oil and natural gas attributable to the full cost pool. Total capitalized costs within the full cost pool were allocated on the basis of the relative fair values of the properties sold and those retained due to substantial economic differences between the properties sold and those retained. 

Other Income (Expense), Net

Other income (expense), net was $(7,362,155) for the year ended December 31, 2013 compared to $3,115,564 for the year ended December 31, 2012. We recognized a loss of $7,077,000 on the warrant liability during 2013. The warrants were not outstanding prior to 2013 and accordingly, no associated warrant revaluation expense was recognized in 2012. 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 $287,934 for the year ended December 31, 2013, compared to $2,614,240 for the year ended December 31, 2012. The decrease in interest expense is due to the pay-off of the outstanding borrowings under our Credit Facility balance during the second quarter of 2013. The other income recognized during 2012 was a result of a $7,213,835 gain recognized, offset by $1,455,787 of acquisition costs incurred in the acquisition of Emerald Oil North America on July 26, 2012 in accordance with GAAP. The gain was the result of the decrease in the share price of our common stock, which was the primary form of consideration for the acquisition, between the announcement date and closing date of the acquisition. We did not acquire any business during the year ended December 31, 2013.

Net Loss Attributable to Common Stockholders

We had net loss attributable to common stockholders of $31,162,092 in 2013 compared to $62,296,099 in 2012 (representing $0.75 and $4.91 per share, respectively). The decrease in net loss attributable to common stockholders in our period-over-period results was driven by increased revenue and production from our oil and natural gas properties, offset by higher general and administrative expenses, preferred stock dividends and deemed dividends.

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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, net gain on acquisition of business, net gain on sale of oil and natural gas properties, net gain (loss) from mark-to-market on commodity derivatives, less cash settlements received (paid) 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:

	Year Ended December 31,
	2014			2013			2012
Net loss	$	(52,145,225	)	$	(10,882,895	)	$	(62,296,099	)
Less: Preferred stock dividends and deemed dividends		—			(20,279,197	)		—
Net loss attributable to common stockholders		(52,145,225	)		(31,162,092	)		(62,296,099	)
Add:   Impairment of oil and natural gas properties		66,430,000			—			61,900,692
Interest expense		4,675,475			287,934			2,614,240
Accretion of discount on asset retirement  obligations		104,803			32,449			14,988
Depletion, depreciation and amortization		35,187,769			17,454,551			12,824,536
Stock-based compensation		11,459,431			12,885,236			7,318,690
Warrant revaluation expense (gain)		(13,504,000	)		7,077,000			—
Preferred stock dividends		—			2,582,191			—
Preferred stock redemption premium		—			6,250,000			—
Accretion of preferred stock issuance discount		—			11,447,006			—
Debt conversion expense		10,438,080			—			—
Net (gains) losses on commodity derivatives		(11,439,240	)		2,656,535			215,439
Gain on sale of oil and natural gas properties, net		—			(7,371,804	)		—
Gain on acquisition of business, net		—			—			(5,758,048	)
Net cash settlements received (paid) on commodity derivatives		5,542,110			(1,984,778	)		(34,191	)
Adjusted EBITDA	$	56,749,203		$	20,154,228		$	16,800,247

Research and Development

We do not anticipate performing any significant product research and development under our current plan of operations.

Off-Balance Sheet Arrangements

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

Critical Accounting Policies and Estimates

The preparation of our consolidated financial statements in conformity with generally accepted accounting principles in the United States, or GAAP, requires our management to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities at the date of our financial statements and the reported amounts of revenues and expenses during the reporting period. The following is a summary of the significant accounting policies and related estimates that affect our financial disclosures. Actual results may differ from these estimates under different assumptions or conditions. For a detailed summary of our significant accounting policies, please refer to Note 2—Basis of Presentation and Significant Accounting Policies under Item 8 of this Annual Report. The following is a summary of the significant accounting policies and related estimates that affect our financial disclosures.

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Oil and Natural Gas Reserves Estimates

Estimating accumulations of oil and natural gas is complex and is not exact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserve estimate is a function of the quality and quantity of available data; the interpretation of that data; the accuracy of various mandated economic assumptions; and the judgment of the persons preparing the estimate.

We believe estimated reserve quantities and the related estimates of future net cash flows are the most important estimates made by an exploration and production company such as ours because they affect the perceived value of our Company, are used in comparative financial analysis ratios, and are used as the basis for the most significant accounting estimates in our financial statements, including the quarterly calculation of depletion, depreciation and impairment of our proved oil and natural gas properties. Proved oil and natural gas reserves are the estimated quantities of crude oil and natural gas, that geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. We determine anticipated future cash inflows and future production and development costs by applying benchmark prices and costs, including transportation, quality and basis differentials, in effect at the end of each quarter to the estimated quantities of oil and natural gas remaining to be produced as of the end of that quarter. We reduce expected cash flows to present value using a discount rate that depends upon the purpose for which the reserve estimates will be used. For example, the standardized measure calculation required by ASC Topic 932, Extractive Activities—Oil and Gas, requires us to apply a 10% discount rate. Although reserve estimates are inherently imprecise, and estimates of new discoveries and undeveloped locations are more imprecise than those of established proved producing oil and natural gas properties, we make considerable effort to estimate our reserves, including through the use of independent reserves engineering consultants. We expect that quarterly reserve estimates will change in the future as additional information becomes available or as oil and natural gas prices and operating and capital costs change. We evaluate and estimate our oil and natural gas reserves as of December 31 of each year and quarterly throughout the year. For purposes of depletion, depreciation, and impairment, we adjust reserve quantities at all quarterly periods for the estimated impact of acquisitions and dispositions. Changes in depletion, depreciation or impairment calculations caused by changes in reserve quantities or net cash flows are recorded in the period in which the reserves or net cash flow estimate changes.

Oil and Natural Gas Properties, Depletion and Full Cost Ceiling Test

We follow the full cost method of accounting for oil and natural gas properties. Under this method, all productive and nonproductive costs incurred in connection with the acquisition of, exploration for and exploitation and development of oil and natural gas reserves are capitalized. Such capitalized costs include costs associated with lease acquisition, geological and geophysical work, delay rentals, drilling, completing and equipping oil and natural gas wells, and salaries, benefits and other internal salary related costs directly attributable to these activities. Proceeds from the disposition of oil and natural gas properties are generally accounted for as a reduction in capitalized costs, with no gain or loss recognized. A gain was recognized on one transaction in 2013 that resulted in the sale of a significant portion of proved reserves as of the transaction date and significantly altered the relationship between capitalized costs and proved reserves attributable to the Williston Basin. For additional discussion please refer to Note 4 – Oil and Natural Gas Properties – Leasehold Sales under Item 8 of this Annual Report.

Depletion of the capitalized costs of oil and natural gas properties, including estimated future development costs, is provided for using the equivalent unit-of-production method based upon estimates of proved oil and natural gas reserves on a quarterly basis. The capitalized costs are amortized over the life of the reserves associated with the assets, with the amortization being expensed as depletion in the period that the reserves are produced. This depletion expense is calculated by dividing the period’s production volumes by the estimated volume of reserves associated with the investment and multiplying the calculated percentage by the sum of the capitalized investment and estimated future development costs associated with the investment. Changes in our reserve estimates will therefore result in changes in our depletion expense per unit. Costs associated with production and general corporate activities are expensed in the period incurred. Unproved property costs not subject to amortization consist primarily of leasehold and seismic costs related to unproved areas. Costs are transferred into the amortization base on an ongoing basis as the properties are evaluated and proved reserves are established or impairment is determined. We will continue to evaluate these properties and costs will be transferred into the amortization base as undeveloped areas are tested. Unproved oil and natural gas properties are not amortized but are assessed, at least annually, for impairment either individually or on an aggregated basis to determine whether we are still actively pursuing the project and whether the project has been proven, either to have economic quantities of reserves or that economic quantities of reserves do not exist.

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Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and 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, impairment would be recognized.

Derivative Instruments

We have entered into commodity derivative instruments, utilizing swaps to reduce the effect of price changes on a portion of our future oil production. Our commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as commodity price risk management assets and liabilities. Net gains and losses on commodity derivatives are recorded based on the changes in the fair values of the derivative instruments. Net gains and losses resulting from the contract settlement of derivatives are recorded in the commodity price risk management activities line on the consolidated statement of income. We value our derivative instruments by obtaining independent market quotes, as well as using industry-standard models that consider various assumptions, including quoted forward prices for commodities, risk free interest rates, and estimated volatility factors, as well as other relevant economic measures. Our valuation estimate takes into consideration the counterparties’ credit worthiness, the Company’s credit worthiness, and the time value of money. The consideration of the factors results in an estimated exit price for each derivative asset or liability under a market place participant’s view. Management believes that this approach provides a reasonable, non-biased, verifiable, and consistent methodology for valuing commodity derivative instruments. For additional discussion please refer to Note 14 – Derivative Instruments and Price Risk Management under Item 8 of this Annual Report.

Warrant Liability

From time to time we 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 our control, or (c) the instruments contain other provisions that causes us to conclude that they are not indexed to our equity. Such instruments are initially recorded at fair value and subsequently adjusted to fair value at the end of each reporting period through earnings.

As a part of the Securities Purchase Agreement with affiliates of White Deer Energy L.P. (“White Deer Energy”), we issued warrants that contain a put and other liability type provisions. Accordingly, these warrants are accounted for as a liability. This warrant liability is accounted for at fair value with changes in fair value reported in earnings. For additional discussion please refer to Note 6 – Preferred and Common Stock under Item 8 of this Annual Report.

Asset Retirement Obligations

We are required to recognize an estimated liability for future costs associated with the abandonment of our oil and gas properties including without limitation the costs of reclamation of our drilling sites, storage and transmission facilities and access roads. We base our estimate of the liability on the industry experience of our management and on our current understanding of federal and state regulatory requirements. Our present value calculations require us to estimate the economic lives of our properties, assume what future inflation rates apply to external estimates and determine the credit- adjusted risk-free rate to use. In periods subsequent to the initial measurement of the asset retirement obligation (“ARO”), we must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to passage of time impact net income as accretion expense. The related capitalized cost, including revisions thereto, is charged to expense through DD&A over the life of the oil and natural gas property.

Income Tax Expense

We account 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.

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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. We have examined the tax positions taken in its tax returns and determined that there are no uncertain tax positions. As a result, we have recorded no uncertain tax liabilities in our consolidated balance sheet.

Revenue Recognition

Our revenue recognition policy is significant because revenue is a key component of our results of operations and the forward-looking statements contained in our analysis of liquidity and capital resources. We derive our revenue primarily from the sale of oil and natural gas. We report revenue as the gross amounts we receive before taking into account production taxes and transportation costs, which are reported as separate expenses. We record revenue in the month our production is delivered to the purchaser, but payment is generally received 30 to 90 days after the date of production. At the end of each month, we make estimates of the amount of production that we delivered to the purchaser and the price we will receive. We record the variances between our estimates and the actual amounts we receive in the month payment is received.

Stock-Based Compensation

We have a stock-based compensation plan that includes restricted stock units (“RSUs”), stock awards, and stock options issued to employees, officers and directors as more fully described in Note 6 — Preferred and Common Stock – Restricted Stock Awards and Restricted Stock Units and Note 7 – Stock Options and Warrants under Item 8 of this Annual Report. We record expense associated with the fair value of stock-based compensation in accordance with ASC 718, Stock Based Compensation. We record compensation expense associated with the issuance of restricted stock shares and RSUs based on the estimated fair value of these awards determined at the time of grant. We recognize compensation cost for performance based grants on a tranche level basis over the requisite service period for the entire award.

Item 7A.   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 years ended December 31, 2014, 2013 and 2012 generally have increased or decreased along with any increases or decreases in oil or natural gas prices, but the exact impact on our income is indeterminable given the variety of expenses associated with producing and selling oil and natural gas that also increase and decrease along with oil and natural gas prices.

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 $5,750,000 in cash settlements during 2014.

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 December 31, 2014 published commodity futures price curves for crude oil, a hypothetical price increase or decrease of $5.00 per Bbl for crude oil would increase or decrease the fair value of our net commodity derivative asset by approximately $600,000. 

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Interest Rate Risk

At December 31, 2014, 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 December 31, 2014, we had (i) $250 million of total borrowings available to us under our Credit Facility, of which, $75.0 million was drawn at year-end. The Credit Facility bears interest at variable rates. Assuming we had the maximum amount outstanding at December 31, 2014 under our credit facility of $250 million, a 1.0% increase in interest rates would result in additional annualized interest expense of $2.5 million. We currently have no interest rate derivative instruments outstanding. However, we may enter into interest rate derivative instruments in the future if we determine that it is necessary to invest in such instruments in order to mitigate our interest rate risk.

For a detailed discussion of the foregoing credit arrangements, including a discussion of the applicable interest rates, please refer to Note 8 – Revolving Credit Facility and Note 9 – Convertible Notes under Item 8 in this Annual Report.

Item 8.   Financial Statements and Supplementary Data

Our Financial Statements required by this item are included on the pages immediately following the Index to Financial Statements beginning on page F- 1.

Item 9.   Changes In and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A.   Controls and Procedures

Evaluation of Disclosure Controls and Procedures

We maintain a system of disclosure controls and procedures that is designed to ensure that information required to be disclosed by us in the reports we file or furnish to the SEC under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures.

As of December 31, 2014, our management, consisting of our Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) pursuant to Rule 13a-15(b) under the Exchange Act. Based upon and as of the date of the evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are designed and effective to ensure that information required to be disclosed is recorded, processed, summarized and reported within the specified periods and is accumulated and communicated to management, consisting of our Chief Executive Officer and Chief Financial Officer, to allow for timely decisions regarding required disclosure of material information required to be included in our periodic SEC reports. Based on the foregoing, our management determined that our disclosure controls and procedures were effective as of December 31, 2014.

In designing and evaluating our disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the control system will be met. In addition, the design of any control system is based in part upon certain assumptions about the likelihood of future events and the application of judgment in evaluating the cost benefit relationship of possible controls and procedures. Because of these and other inherent limitations of control systems, there is only reasonable assurance that our controls will succeed in achieving their goals under all potential future conditions.

There have been no changes (including corrective actions with regard to significant deficiencies of material weaknesses) 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.

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Management’s Annual Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). The design of any system of controls is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions, regardless of how remote. All internal control systems, no matter how well designed, have inherent limitations. Our internal control over financial reporting consists of the following policies and procedures that:

· Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;

· Provide reasonable assurance that transactions are recorded as necessary to permit preparation of the financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and

· Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

We carried out an evaluation, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our internal controls over financial reporting as of December 31, 2014. In making this assessment, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in “Internal Control — Integrated Framework (2013).” Based on this assessment, management believes that, as of December 31, 2014, our internal control over financial reporting was effective based on those criteria.

The effectiveness of our internal control over financial reporting as of December 31, 2014 has been audited by BDO USA, LLP, an independent registered public accounting firm, as stated in their report which is included in this annual report on Form 10-K.

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Report of Independent Registered Public Accounting Firm

Board of Directors and Stockholders

Emerald Oil, Inc.

Denver, Colorado

We have audited Emerald Oil, Inc.’s internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Emerald Oil, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying “Item 9A, Management’s Annual Report on Internal Control Over Financial Reporting.” Our responsibility is to express an opinion on Emerald Oil, Inc.’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Emerald Oil, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the balance sheet of Emerald Oil, Inc. as of December 31, 2014 and 2013, and the related statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2014 and our report dated March 10, 2015 expressed an unqualified opinion thereon.

/s/ BDO USA, LLP

Houston, Texas

March 10, 2015

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Item 9B.   Other Information

None.

PART III

Item 10.   Directors, Executive Officers and Corporate Governance

The information required by this item is incorporated herein by reference to the 2014 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2014.

Item 11.   Executive Compensation

The information required by this item is incorporated herein by reference to the 2014 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2014.

Item 12.   Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters

The information required by this item is incorporated herein by reference to the 2014 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2014.

Item 13.   Certain Relationships and Related Transactions, and Director Independence

The information required by this item is incorporated herein by reference to the 2014 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2014.

Item 14.   Principal Accountant Fees and Services

The information required by this item is incorporated herein by reference to the 2014 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2014.

PART IV

Item 15.   Exhibits and Financial Statement Schedules

(a) Documents filed as Part of this Report:

1.  Financial Statements

See Index to Financial Statements on page F- 1.

2.  Financial Statement Schedules

All schedules are omitted because they are either not applicable or required information is shown in the financial statements or notes thereto.

3.  Exhibits

The exhibits set forth in the accompanying Exhibit Index are filed or incorporated by reference as part of this Form 10-K.

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Exhibit Index

Exhibit No.	Description of Exhibit
2.1	Agreement and Plan of Merger, dated June 11, 2014, by and 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. (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 Ownership and Merger by and between Emerald Oil, Inc., a Montana corporation, and Emerald Oil, Inc., a Delaware corporation (filed as Exhibit 3.3 to the Company’s Current Report on Form 8-K filed on June 12, 2014, and incorporated herein by reference).
3.3	Articles of Merger of Emerald Oil, Inc., a Montana corporation,  into and Emerald Oil, Inc., a Delaware corporation, dated June 11, 2014 (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).
3.4	Amended and Restated Bylaws of Emerald Oil, Inc. (filed as Exhibit 3.2 to the Company’s Current Report on Form 8-K filed on December 24, 2014, and incorporated herein by reference).
4.1	Form of Stock Certificate of Emerald Oil, Inc. (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on June 12, 2014, and incorporated herein by reference).
4.2	Form of Warrant to Purchase Common Stock issued to investors in the February 2013 private placement (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on February 19, 2013, and incorporated herein by reference).
4.3	Indenture, dated as of March 24, 2014, between Emerald Oil, Inc. and U.S. Bank National Association, as trustee (including the form of Convertible Notes) (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on March 24, 2014, and incorporated herein by reference).
**10.1	Emerald Oil, Inc. Second Amended and Restated 2011 Equity Incentive Plan (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on July 12, 2013, and incorporated herein by reference).
**10.2	Form of Incentive Stock Option Agreement under the 2011 Equity Incentive Plan (filed as Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q filed on November 8, 2011, and incorporated herein by reference).

57

Exhibit No.	Description of Exhibit
**10.3	Form of Nonqualified Stock Option Agreement under the 2011 Equity Incentive Plan (filed as Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q filed on November 8, 2011, and incorporated herein by reference).
**10.4	Form of Restricted Stock Agreement under the 2011 Equity Incentive Plan (filed as Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q filed on November 8, 2011, and incorporated herein by reference).
**10.5	Form of Restricted Stock Unit Agreement under the 2011 Equity Incentive Plan (filed as Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q filed on November 8, 2011, and incorporated herein by reference).
**10.6	Employment Agreement, dated as of September 18, 2013, by and between Emerald Oil, Inc. and McAndrew Rudisill (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on September 18, 2013, and incorporated herein by reference).
**10.7	Second Amended and Restated Employment Agreement, dated as of September 18, 2013, by and between Emerald Oil, Inc. and Michael Krzus (filed as Exhibit 10.5 to the Company’s Current Report on Form 8-K filed on September 18, 2013, and incorporated herein by reference).
**10.8	Employment Agreement, dated as of September 18, 2013, by and between Emerald Oil, Inc. and James Russell (J.R.) Reger (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on September 18, 2013, and incorporated herein by reference).
**10.9	Employment Agreement, dated as of September 18, 2013,  by and between Emerald Oil, Inc. and Paul Wiesner (filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on September 18, 2013, and incorporated herein by reference).
**10.10	Employment Agreement, dated as of September 18, 2013, by and between Emerald Oil, Inc. and David Veltri (filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on September 18, 2013, and incorporated herein by reference).
**10.11	Amended and Restated Employment Agreement between Ryan Smith and Emerald Oil, Inc., dated effective as of September 10, 2014 (filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on September 12, 2014, and incorporated herein by reference).
**10.12	Employment Agreement, dated as of September 18, 2013, by and between Emerald Oil, Inc. and Michael Dickinson (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on December 11, 2014, and incorporated herein by reference).
10.13	Credit Agreement, dated as of November 20, 2012, among Emerald Oil, Inc., as Borrower, Wells Fargo Bank, N.A., as Administrative Agent, and the Lenders party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on November 21, 2012, and incorporated herein by reference).

58

Exhibit No.	Description of Exhibit
10.14	First Amendment to Credit Agreement, dated as of February 18, 2013, by and among Emerald Oil, Inc., the guarantors party thereto, the lenders party thereto and Wells Fargo Bank, N.A., as administrative agent for the Lenders (filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on February 19, 2013, and incorporated herein by reference).
10.15	Second Amendment to Credit Agreement, dated as of March 24, 2014, among Emerald Oil, Inc., the guarantors party thereto, Wells Fargo Bank, N.A., as administrative agent, and the lenders party thereto (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on March 24, 2014, and incorporated herein by reference)
10.16	Amended and Restated Credit Agreement, dated as of May 1, 2014, among Emerald Oil, Inc., the guarantors party thereto, Wells Fargo Bank, N.A., as administrative agent, and the lenders party thereto (filed as Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q filed on May 5, 2014, and incorporated herein by reference)
10.17	First Amendment to Amended and Restated Credit Agreement, dated as of September 2, 2014, among Emerald Oil, Inc., the guarantors party thereto, Wells Fargo, Bank, N.A., as administrative agent, and the lenders party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on September 4, 2014, and incorporated herein by reference).
10.18	Securities Purchase Agreement, dated as of February 1, 2013, by and among Emerald Oil, Inc., WDE Emerald Holdings LLC and White Deer Energy FI L.P. (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on February 6, 2013, and incorporated herein by reference).
10.19	Registration Rights Agreement, dated as of February 19, 2013, by and among Emerald Oil, Inc., WDE Emerald Holdings LLC and White Deer Energy FI L.P. (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on February 19, 2013, and incorporated herein by reference).
10.20	Amendment No. 1, dated June 4, 2013, to the Registration Rights Agreement dated as of February 19, 2013, by and among Emerald Oil, Inc., WDE Emerald Holdings LLC and White Deer Energy FI L.P. (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on June 4, 2013, and incorporated herein by reference).
10.21	Amendment No. 2, dated as of October 17, 2013, to the Registration Rights Agreement dated as of February 19, 2013, by and among Emerald Oil, Inc., WDE Emerald Holdings LLC and White Deer Energy FI L.P. (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on October 17, 2013, and incorporated herein by reference).
10.22	Securities Purchase Agreement, dated as of May 13, 2013, by and among Emerald Oil, Inc., WDE Emerald Holdings LLC and White Deer Energy FI L.P. (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on May 15, 2013, and incorporated herein by reference).
10.23	Securities Purchase Agreement, dated as of September 23, 2013, by and among Emerald Oil, Inc., WDE Emerald Holdings LLC and White Deer Energy FI L.P (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on September 23, 2013, and incorporated herein by reference).

59

Exhibit No.	Description of Exhibit
10.24	Form of Indemnification Agreement (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on February 19, 2013, and incorporated herein by reference).
10.25	Purchase and Sale Agreement, dated as of August 1, 2014, by and among Emerald Oil, Inc., Emerald WB LLC, Liberty Resources Management Company, LLC, Liberty Resources Bakken Operating, LLC, and Liberty Resources II, LLC (filed as Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q filed on August 4, 2014, and incorporated herein by reference)
10.26	Purchase and Sale Agreement, dated January 9, 2014, by and among Kodiak Oil & Gas (USA) Inc., Emerald Oil, Inc. and Emerald WB LLC (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on January 10, 2014, and incorporated herein by reference).
10.27	Form of Exchange Agreement (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on December 11, 2014, and incorporated herein by reference).
*12.1	Computation of Ratio of Earnings to Fixed Charges.
*21.1	List of Subsidiaries.
*23.1	Consent of Independent Registered Public Accounting Firm BDO USA, LLP.
*23.2	Consent of Netherland, Sewell & Associates, Inc.
*24.1	Power of Attorney (included on signature page).
*31.1	Certification of the Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2	Certification of the Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934, 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.

60

Exhibit No.	Description of Exhibit
*99.1	Report of Netherland, Sewell & Associates, Inc.
*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.

*	Indicates exhibits filed herewith.
**	Indicates management contract or compensatory plan or arrangement.

61

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	EMERALD OIL, INC.
Date: March 10, 2015	By: /s/ MCANDREW RUDISILL
	McAndrew Rudisill
	Chief Executive Officer

POWER OF ATTORNEY

Each person whose signature appears below constitutes and appoints, McAndrew Rudisill and Ryan Smith, or either of them, his true and lawful attorney-in-fact and agent, acting alone, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K and to file the same, with all exhibits thereto, and other documents in connection wherewith, with the Commission, granting unto said attorney-in-fact and agent, each acting alone, full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all said attorney-in-fact and agent, acting alone, or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacity and on the dates indicated:

Signature	Title	Date
/s/ MCANDREW RUDISILL McAndrew Rudisill	Director; Chief Executive Officer (principal executive officer)	March 10, 2015
/s/ RYAN SMITH Ryan Smith	Chief Financial Officer (principal financial officer and principal accounting officer)	March 10, 2015
/s/ JAMES RUSSELL (J.R.) REGER James Russell (J.R.) Reger	Director	March 10, 2015
/s/ BEN A. GUILL Ben A. Guill	Director	March 10, 2015
/s/ DUKE R. LIGON Duke R. Ligon	Director	March 10, 2015
/s/ DANIEL L. SPEARS Daniel L. Spears	Director	March 10, 2015
/s/ SETH SETRAKIAN Seth Setrakian	Director	March 10, 2015

62

EMERALD OIL, INC.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets as of December 31, 2014 and 2013	F-3
Consolidated Statements of Operations for the Years Ended December 31, 2014, 2013 and 2012	F-4
Consolidated Statements of Cash Flows for the Years Ended December 31, 2014, 2013 and 2012	F-5
Consolidated Statements of Stockholders’ Equity  for the Years Ended December 31, 2014, 2013 and 2012	F-6
Notes to the Consolidated Financial Statements	F-7

F-1

Report of Independent Registered Public Accounting Firm

Board of Directors and Stockholders

Emerald Oil, Inc.
Denver, Colorado

We have audited the accompanying consolidated balance sheets of Emerald Oil, Inc. as of December 31, 2014 and 2013 and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Emerald Oil, Inc. at December 31, 2014 and 2013, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Emerald Oil, Inc.’s internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 10, 2015 expressed an unqualified opinion thereon.

/s/ BDO USA, LLP

Houston, Texas

March 10, 2015

F-2

EMERALD OIL, INC.
CONSOLIDATED BALANCE SHEETS

AS OF DECEMBER 31,

	December 31, 2014			December 31, 2013
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	12,389,230		$	144,255,438
Restricted Cash		—			15,000,512
Accounts Receivable – Oil and Natural Gas Sales		7,203,455			8,715,821
Accounts Receivable – Joint Interest Partners		31,842,464			31,523,204
Other Receivables		980,317			577,409
Prepaid Expenses and Other Current Assets		289,061			206,299
Fair Value of Commodity Derivatives		5,044,125			—
Total Current Assets		57,748,652			200,278,683
PROPERTY AND EQUIPMENT
Oil and Natural Gas Properties, Full Cost Method, at cost:
Proved Oil and Natural Gas Properties		593,472,170			211,015,067
Unproved Oil and Natural Gas Properties		166,708,263			57,015,315
Equipment and Facilities		6,086,896			1,837,744
Other Property and Equipment		2,583,372			890,811
Total Property and Equipment		768,850,701			270,758,937
Less – Accumulated Depreciation, Depletion and Amortization		(149,703,417	)		(48,176,522	)
Total Property and Equipment, Net		619,147,284			222,582,415
Restricted Cash		4,000,000			6,000,000
Fair Value of Commodity Derivatives		—			68,396
Debt Issuance Costs, Net of Amortization		5,779,125			475,157
Deposits on Acquisitions		140,173			125,368
Deferred Tax Asset, Net		1,813,796			—
Other Non-Current Assets		430,846			357,644
Total Assets	$	689,059,876		$	429,887,663
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts Payable	$	120,136,903		$	63,168,422
Fair Value of Commodity Derivatives		—			921,401
Accrued Expenses		11,267,831			11,821,729
Advances from Joint Interest Partners		2,577,247			2,205,538
Deferred Tax Liability, Net		1,813,796			—
Total Current Liabilities		135,795,777			78,117,090
LONG-TERM LIABILITIES
Revolving Credit Facility		75,000,000			—
Convertible Senior Notes		151,500,000			—
Asset Retirement Obligations		2,671,975			692,137
Warrant Liability		2,199,000			15,703,000
Other Non-Current Liabilities		—			56,327
Total Liabilities		367,166,752			94,568,554
COMMITMENTS AND CONTINGENCIES
Preferred Stock – Par Value $.001; 20,000,000 Shares Authorized;
Series B Voting Preferred Stock – 5,114,633 issued and outstanding at December 31, 2014 and December 31, 2013. Liquidation preference value of $5,115 as of December 31, 2014 and December 31, 2013.		5,000			5,000
STOCKHOLDERS’ EQUITY
Common Stock, Par Value $.001; 500,000,000 Shares Authorized, 77,828,613 and 65,840,370 Shares Issued and Outstanding, respectively		77,828			65,840
Additional Paid-In Capital		455,008,596			416,301,344
Accumulated Deficit		(133,198,300	)		(81,053,075	)
Total Stockholders’ Equity		321,888,124			335,314,109
Total Liabilities and Stockholders’ Equity	$	689,059,876		$	429,887,663

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

F-3

EMERALD OIL, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2014			2013			2012
REVENUES
Oil Sales	$	98,532,131		$	52,609,790		$	27,264,526
Natural Gas Sales		2,636,460			1,371,250			865,459
Net Gain (Losses) on Commodity Derivatives		11,439,240			(2,656,535	)		(215,439	)
Total Revenues		112,607,831			51,324,505			27,914,546
OPERATING EXPENSES
Production Expenses		20,559,423			8,520,414			2,727,133
Production Taxes		11,010,300			5,702,521			2,955,015
General and Administrative Expenses		25,186,682			30,507,114			12,903,845
Depletion of Oil and Natural Gas Properties		34,798,218			17,310,059			12,770,718
Impairment of Oil and Natural Gas Properties		66,430,000			—			61,900,692
Depreciation and Amortization		389,551			144,492			53,818
Accretion of Discount on Asset Retirement Obligations		104,803			32,449			14,988
Acquisition Costs		409,712			—			—
Early Rig Termination Expense		4,286,906			—			—
Gain on Sale of Oil and Natural Gas Properties		—			(7,371,804	)		—
Total  Operating Expenses		163,175,595			54,845,245			93,326,209
LOSS FROM OPERATIONS		(50,567,764	)		(3,520,740	)		(65,411,663	)
OTHER INCOME (EXPENSE)
Interest Expense		(4,675,475	)		(287,934	)		(2,614,240	)
Warrant Revaluation Gain (Expense)		13,504,000			(7,077,000	)		—
Debt Conversion Expense		(10,438,080	)		—			—
Gain on Acquisition of Business, Net		—			—			5,758,048
Other Income (Expense)		32,094			2,779			(28,244	)
Total Other Income (Expense), Net		(1,577,461	)		(7,362,155	)		3,115,564
LOSS BEFORE INCOME TAXES		(52,145,225	)		(10,882,895	)		(62,296,099	)
INCOME TAX PROVISION		—			—			—
NET LOSS		(52,145,225	)		(10,882,895	)		(62,296,099	)
Less: Preferred Stock Dividends and Deemed Dividends		—			(20,279,197	)		—
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	(52,145,225	)	$	(31,162,092	)	$	(62,296,099	)
Net Loss Per Common Share – Basic and Diluted	$	(0.78	)	$	(0.75	)	$	(4.91	)
Weighted Average Shares Outstanding – Basic and Diluted		66,772,458			41,383,277			12,699,544

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

F-4

EMERALD OIL, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2014			2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss	$	(52,145,225	)	$	(10,882,895	)	$	(62,296,099	)
Adjustments to Reconcile Net Loss to Net Cash Provided By (Used For) Operating Activities:
Depletion of Oil and Natural Gas Properties		34,798,218			17,310,059			12,770,718
Impairment of Oil and Natural Gas Properties		66,430,000			—			61,900,692
Depreciation and Amortization		389,551			144,492			53,818
Amortization of Debt Issuance Costs		1,711,171			127,857			1,929,561
Accretion of Discount on Asset Retirement Obligations		104,803			32,449			14,988
Net (Gains) Losses on Commodity Derivatives		(11,439,240	)		2,656,535			215,439
Net Cash Settlements Received (Paid) on Commodity Derivatives		5,542,110			(1,984,778	)		(34,191	)
Gain on Sale of Oil and Natural Gas Properties, Net		—			(7,371,804	)		—
Gain on Acquisition of Business		—			—			(7,213,835	)
Warrant Revaluation Expense (Gain)		(13,504,000	)		7,077,000			—
Share-Based Compensation Expense		11,459,431			12,885,209			7,318,690
Debt Conversion Expense		10,438,080			—			—
Changes in Assets and Liabilities:
(Increase) Decrease in Trade Receivables – Oil and Natural Gas Revenues		1,512,366			(200,956	)		(5,267,453	)
Increase in Accounts Receivable – Joint Interest Partners		(319,260	)		(27,464,913	)		(4,058,291	)
(Increase) Decrease in Other Receivables		(402,908	)		556,440			(1,133,849	)
Increase in Prepaid Expenses and Other Current Assets		(82,762	)		(103,126	)		(54,843	)
Increase in Other Non-Current Assets		(73,201	)		(96,869	)		(100,100	)
Increase in Accounts Payable		9,152,337			2,831,342			30,123
Increase (Decrease) in Accrued Expenses		(7,055,970	)		8,412,533			214,399
Increase (Decrease) in Other Non-Current Liabilities		(56,327	)		56,327			—
Increases in Advances from Joint Interest Partners		371,709			2,205,538			—
Net Cash Provided By Operating Activities		56,830,883			6,190,440			4,289,767
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of Other Property and Equipment		(1,692,561	)		(505,788	)		(172,785	)
Restricted Cash Released		17,000,512			—			—
Restricted Cash Received		—			(21,000,512	)		—
Payments of Restricted Cash		(2,648,721	)		—			—
Increase in Deposits for Acquisitions		(14,805	)		(125,368	)		—
Use of (Payments for) Prepaid Drilling Costs		—			100,193			(67,030	)
Proceeds from Sale of Oil and Natural Gas Properties, Net of Transaction Costs		36,155,859			129,432,743			—
Investment in Oil and Natural Gas Properties		(478,068,380	)		(182,901,806	)		(66,212,818	)
Net Cash Used For Investing Activities		(429,268,096	)		(75,000,538	)		(66,452,633	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the Issuance of Convertible Notes, Net of Transactions Costs		166,893,211			—			—
Proceeds from Issuance of Common Stock, Net of Transaction Costs		—			238,354,687			72,167,012
Proceeds from Issuance of Preferred Stock, Net of Transaction Costs		—			47,183,994			—
Payments on Preferred Stock		—			(50,000,000	)		—
Advances on Revolving Credit Facility and Term Loan		110,000,000			—			56,530,730
Payments on Revolving Credit Facility		(35,000,000	)		(23,500,000	)		(33,030,730	)
Payments of Senior Secured Promissory Notes		—			—			(15,000,000	)
Payment of Assumed Liabilities		—			—			(20,303,903	)
Cash Paid for Finance Costs		(24,605	)		(333,333	)		(1,935,131	)
Preferred Stock Dividends and Deemed Dividends		—			(8,832,191	)		—
Cash Paid for Debt Issuance Costs		(1,408,351	)		—			—
Proceeds from Exercise of Stock Options and Warrants		110,750			—			—
Net Cash Provided by Financing Activities		240,571,005			202,873,157			58,427,978
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(131,866,208	)		134,063,059			(3,734,888	)
CASH AND CASH EQUIVALENTS – BEGINNING OF PERIOD		144,255,438			10,192,379			13,927,267
CASH AND CASH EQUIVALENTS – END OF PERIOD	$	12,389,230		$	144,255,438		$	10,192,379
Supplemental Disclosure of Cash Flow Information
Cash Paid During the Period for Interest	$	2,121,184		$	255,776		$	1,154,943
Cash Paid During the Period for Income Taxes	$	—		$	—		$	—
Non-Cash Financing and Investing Activities:
Oil and Natural Gas Properties Included in Account Payable	$	107,957,324		$	60,141,180		$	38,973,137
Stock-Based Compensation Capitalized to Oil and Natural Gas Properties	$	2,273,656		$	1,193,960		$	582,040
Accretion on Preferred Stock Issuance Discount	$	—		$	8,626,000		$	—
Accretion of Preferred Stock Issuance Costs	$	—		$	2,816,000		$	—
Asset Retirement Obligation Costs and Liabilities	$	1,966,907		$	676,240		$	164,967
Asset Retirement Obligations Associated With Properties Sold	$	19,317		$	312,625		$	—
Asset Retirement Obligations Settled through P&A	$	72,556		$	—		$	—
Common Stock Issued for Oil and Natural Gas Properties	$	—		$	6,736,935		$	—
Debt Extinguished in Conversion of Convertible Notes	$	21,000,000		$	—		$	—
Purchases through Issuance of Common Stock or Assumption of Liabilities:
Oil and Natural Gas Properties	$	—		$	—		$	40,787,238
Other Property and Equipment	$	—		$	—		$	36,000
Other Non-Current Assets	$	—		$	—		$	75,000
Non-Cash Acquisition of Business Amounts:
Fair Market Value of Common Stock Issued	$	—		$	—		$	13,380,501
Debt Assumed	$	—		$	—		$	20,303,903

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

F-5

EMERALD OIL, INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (DEFICIT)
FOR THE YEARS ENDED DECEMBER 31, 2014, 2013 AND 2012

	Common Stock
	Shares			Amount			Additional Paid-in Capital			Accumulated Deficit			Total Stockholders’ Equity
Balance – December 31, 2011		8,264,062		$	8,264		$	87,007,758		$	(7,874,081	)	$	79,141,941
Common Shares Issued as Compensation		910,296			910			3,837,212			—			3,838,122
Restricted Stock Grants		74,285			74			(74	)		—			—
Restricted Stock Forfeited		(53,572	)		(53	)		53			—			—
Restricted Stock Grant Compensation		—			—			1,178,559			—			1,178,559
Compensation Related to Stock Option Grants		—			—			1,779,901			—			1,779,901
Director Fees Related to Stock Option Grants		—			—			1,104,147			—			1,104,147
Issuance of Common Shares for the Acquisition of Emerald Oil North America, Inc.		1,662,174			1,662			13,378,839			—			13,380,501
Net Proceeds from Equity Offering		13,877,555			13,878			72,153,134			—			72,167,012
Reverse Split Reconciliation Due to Fractional Shares		(157	)		—			—			—			—
Net Loss		—			—			—			(62,296,099	)		(62,296,099	)
Balance – December 31, 2012		24,734,643			24,735			180,439,530			(70,170,180	)		110,294,085
Common shares issued for oil and natural gas properties		1,165,015			1,165			6,735,770			—			6,736,935
Stock-based compensation		—			—			13,378,158			—			13,378,158
Restricted Stock Vesting, Net of Tax Withholding		1,012,260			1,012			(2,288,675	)		—			(2,287,663	)
Equity offering		38,928,452			38,928			238,315,759			—			238,354,687
Redemption of Preferred Stock and Accretion of Issuance Discount		—			—			(17,697,007	)		—			(17,697,007	)
Preferred Stock Dividends Paid		—			—			(2,582,191	)		—			(2,582,191	)
Net loss		—			—			—			(10,882,895	)		(10,882,895	)
Balance – December 31, 2013		65,840,370			65,840			416,301,344			(81,053,075	)		335,314,109
Stock-based compensation		—			—			11,283,929			—			11,283,929
Restricted Stock Vesting, Net of Tax Withholding		—			—			(4,011,910	)		—			(4,011,910	)
Restricted Stock Grants		1,266,419			1,266			(1,266	)		—			—
Common shares issued to extinguish convertible debt		10,721,824			10,722			31,427,358			—			31,438,080
Transaction costs related to prior year offering		—			—			33,746			—			33,746
Stock option exercise		—			—			(24,605	)		—			(24,605	)
Net loss		—			—			—			(52,145,225	)		(52,145,225	)
Balance – December 31, 2014		77,828,613		$	77,828		$	455,008,596		$	(133,198,300	)	$	321,888,124

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

F-6

EMERALD OIL, INC.
Notes to Consolidated Financial Statements

NOTE 1  ORGANIZATION AND NATURE OF BUSINESS

Description of Operations — Emerald Oil, Inc. (the “Company”), a Delaware corporation, 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.

The Company added executive management that is experienced in exploration and production of oil and natural gas resources with the acquisition of Emerald Oil North America, Inc., formerly known as Emerald Oil, Inc. (“Emerald Oil North America”), on July 26, 2012 (see Note 3 – Acquisition of Business). The Company continues to add to these internal capabilities and leveraged best practices through partnering with industry experts. Currently, the Company has 42 employees and retains independent contractors to assist in operating and managing oil and natural gas development.

NOTE 2  BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES

These consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The accompanying consolidated financial statements include the accounts of Emerald Oil, Inc. and its direct and indirect wholly owned subsidiaries. All significant intercompany accounts and transactions have been eliminated.

Reverse Stock Split

On October 22, 2012, a majority of the Company’s stockholders approved a 1-for-7 reverse stock split pursuant to which all stockholders of record received one share of common stock for each seven shares of common stock owned (subject to minor adjustments as a result of fractional shares). This reverse stock split decreased the issued and outstanding common shares by approximately 140,339,000, the outstanding warrants by approximately 6,700,000 and the outstanding stock options by approximately 4,100,000. GAAP requires that the reverse stock split be applied retrospectively to all periods presented. As a result, all stock, warrant and option transactions described herein have been adjusted to reflect the 1-for-7 reverse stock split.

Cash and Cash Equivalents

The Company considers highly liquid investments with insignificant interest rate risk and original maturities of three months or less to be cash equivalents. Cash equivalents consist primarily of interest-bearing bank accounts and money market funds. The Company’s cash positions represent assets held in checking and money market accounts. These assets are generally available to the Company on a daily or weekly basis and are highly liquid in nature. Due to the balances being greater than the Federal Deposit Insurance Corporation (FDIC) limits of $250,000 per institution per depositor, the Company does not have insurance coverage on the entire amount of its bank deposits. The Company believes this risk to be minimal. In addition, the Company has access 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 consolidated balance sheets totaled $4 million and $21 million at December 31, 2014 and December 31, 2013, respectively.  At December 31, 2014, the $4 million balance related to a drilling commitment agreement entered into pursuant to oil and natural gas leases. As of December 31, 2013, there was an additional $11.0 million of restricted cash related to a portion of proceeds from a leasehold sale held in escrow until finalization of standard due diligence procedures. On February 21, 2014, $8.6 million was released to the Company, with the remaining $2.4 million returned to the buyer for purchase price adjustments.

F-7

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 years ended December 31, 2014, 2013 and 2012.

Concentrations of Credit Risk

Financial instruments that potentially subject us to concentrations of credit risk consist principally of cash and cash equivalents, accounts receivable and derivative contracts. We control our exposure to credit risk associated with these instruments by (i) placing our assets and other financial interests with creditworthy financial institutions, (ii) maintaining policies over credit extension that include the evaluation of customers’ financial condition and monitoring payment history, although we do not have collateral requirements and (iii) netting derivative assets and liabilities for counterparties where we have a legal right of offset.

At December 31, 2014 and 2013, the cash and cash equivalents were concentrated in one financial institution. We periodically assess the financial condition of this institution and believe that any possible credit risk is minimal.

During the year ended December 31, 2014, 81% of the Company’s production was sold to two customers. However, the Company does not believe that the loss of a single purchaser, including these two, would materially affect the Company’s business because there are numerous other purchasers in the area in which the Company sells its production. For the years ended December 31, 2014, 2013 and 2012, purchases by the following companies exceeded 10% of the total oil and natural gas revenues of the Company.

	For the Years Ended December 31,
	2014			2013			2012
Customer A		59	%		24	%		—
Customer B		22	%		12	%		—

Our customers are in the energy industry and they may be similarly affected by changes in economic or other conditions.

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 acquisition, and exploration activities. For the years ended December 31, 2014, 2013 and 2012, the Company capitalized $5,340,034, $3,443,462 and $842,418, respectively, of internal salaries, which included $2,273,656, $1,193,960 and $582,040, 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 interest of $362,688 for the year ended December 31, 2012. The Company did not capitalize interest for the years ended December 31, 2014 and 2013.

Proceeds from property sales will generally be credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. The Company closed property sales during the years ended December 31, 2014 and 2013 in the Williston Basin and Sand Wash Basin (see Note 4 – Oil and Natural Gas Properties). A gain was recognized on one transaction in 2013 that resulted in the sale of a significant portion of proved reserves as of the transaction date and significantly altered the relationship between capitalized costs and proved reserves attributable to the Williston Basin. No gain or loss was recognized on any other sales during the period. The Company engages in acreage trades in the Williston Basin, but these trades are generally for acreage that is similar both in terms of geographic location and potential resource value.

F-8

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 years ended December 31, 2014, 2013 and 2012, the Company included $2,979,258, $3,020,485 and $3,625,209, 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. Based on calculated reserves at December 31, 2014, 2013 and 2012, the unamortized costs of the Company’s oil and natural gas properties exceeded the ceiling test limit by $66,430,000, $0 and $51,709,458 respectively. The Company also recognized that oil and natural gas properties exceeded the ceiling test limit as of June 30, 2012 by $10,191,234. As a result, the Company was required to record impairment of the net capitalized costs of its oil and natural gas properties in the amount of $66,430,000, $0 and $61,900,692 for the years ended December 31, 2014, 2013, and 2012, respectively.

Oil and Natural Gas Reserve Quantities

Emerald’s estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Emerald’s reserve estimates are prepared by the independent engineering firm, Netherland, Sewell & Associates, Inc. The estimate of Emerald’s proved reserves as of December 31, 2014, 2013 and 2012 have been prepared and presented in accordance with SEC rules and accounting standards.

Reserves and their relation to estimated future net cash flows impact Emerald’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Emerald prepares its reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines on a quarterly basis. The independent engineering firm described above adheres to the same guidelines when preparing the year-end reserve report. The accuracy of Emerald’s reserve estimates is a function of many factors including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates.

Emerald’s proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil and natural gas eventually recovered.

F-9

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. Depreciation expense was $389,551, $144,492 and $53,818 for the years ended December 31, 2014, 2013 and 2012, respectively.

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

Asset Retirement Obligations

The Company records the fair value of a liability for an asset retirement obligation in the period in which the liability 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 proven reserves were not adequate to cover the current imbalance situation. As of December 31, 2014 and 2013, the Company’s natural gas production was in balance, i.e., its cumulative portion of natural gas production taken and sold from wells in which it has an interest equaled the Company’s entitled interest in natural gas production from those wells.

Stock-Based Compensation

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

On May 27, 2011, the stockholders of the Company approved the 2011 Equity Incentive Plan (the “2011 Plan”), under which 714,286 shares of common stock were reserved. On October 22, 2012, the stockholders of the Company approved an amendment to the 2011 Plan to increase the number of shares available for issuance under the 2011 Plan to 3,500,000 shares. 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 9,800,000 shares. The purpose of the 2011 Plan is to promote the success of the Company and its affiliates by facilitating the employment and retention of competent personnel and by furnishing incentives to those officers, directors and employees upon whose efforts the success of the Company and its affiliates will depend to a large degree. It is the intention of the Company to carry out the 2011 Plan through the granting of incentive stock options, nonqualified stock options, restricted stock awards, restricted stock unit awards, performance awards and stock appreciation rights. As of December 31, 2014, 1,211,563 stock options and 3,791,502 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 584,620 nonvested restricted stock units. As of December 31, 2014, there are 4,796,935 shares available for issuance under the 2011 Plan.

F-10

Income Taxes

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

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

Net Income (Loss) Per Common Share

Basic net income (loss) per common share is based on the net income (loss) divided by the weighted average number of common shares outstanding during the period. Diluted earnings per share are computed using the weighted average number of common shares plus dilutive common share equivalents outstanding during the period using the treasury stock method. In the computation of diluted earnings per share, excess tax benefits that would be created upon the assumed vesting of nonvested restricted shares or the assumed exercise of stock options (i.e., hypothetical excess tax benefits) are included in the assumed proceeds component of the treasury stock method to the extent that such excess tax benefits are more likely than not to be realized. When a loss from continuing operations exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share. As the Company had losses for the years ended December 31, 2014, 2013 and 2012, the potentially dilutive shares were anti-dilutive and were thus not included in the net loss per share calculation.

 As of December 31, 2014, (i) 584,620 nonvested restricted stock units were issued and outstanding and represented potentially dilutive shares; (ii) 562,673 stock options were issued and exercisable and represented potentially dilutive shares; (iii) 632,006 stock options were granted but were not exercisable and represented potentially dilutive shares; (iv) 5,114,633 warrants were issued and exercisable at an exercise price of $3.02 and represented dilutive shares; (v) 223,293 warrants were issued and exercisable at an exercise price of $6.86 and represented potentially dilutive shares; (vi) 892,858 warrants were issued and exercisable at an exercise price of $49.70 and represented potentially dilutive shares; and (vii) $151.5 million of convertible senior notes convertible into approximately 17,264,958 common shares as of December 31, 2014 and represented potentially dilutive shares.

Derivative and Other Financial Instruments

Commodity Derivative Instruments

The Company has entered into commodity derivative instruments, utilizing oil derivative swap contracts to reduce the effect of price changes on a portion of future oil production. The Company’s commodity derivative instruments are measured at fair value and are included in the consolidated balance sheet as derivative assets and liabilities. Net gains and losses are recorded based on the changes in the fair values of the derivative instruments. The Company’s valuation estimate takes into consideration the counterparties’ credit worthiness, the Company’s credit worthiness, and the time value of money. The consideration of the factors results in an estimated exit price for each derivative asset or liability under a market place participant’s view. Management believes that this approach provides a reasonable, non-biased, verifiable, and consistent methodology for valuing commodity derivative instruments (see Note 14 – Derivative Instruments and Price Risk Management).

Warrant Liability

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

F-11

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

New Accounting Pronouncements

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

Use of Estimates

The preparation of consolidated financial statements under GAAP in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates relate to proved oil and natural gas reserve volumes, future development costs, estimates relating to certain oil and natural gas revenues and expenses, fair value of derivative instruments, valuation of share-based compensation 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 prior periods’ reported amounts 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  ACQUISITION OF BUSINESS

On July 9, 2012, the Company entered into a Securities Purchase Agreement (the “Purchase Agreement”) with Emerald Oil & Gas NL (the “Parent”) and Emerald Oil North America, Inc., a wholly owned subsidiary of the Parent, pursuant to which the Company purchased all of the outstanding capital stock of Emerald Oil North America for approximately 19.9% of the total shares of the Company’s common stock outstanding as of the closing date. The Company completed the acquisition of Emerald Oil North America on July 26, 2012 and issued approximately 1.66 million shares to the Parent. The Company assumed Emerald Oil North America’s liabilities, including approximately $20.3 million in debt owed by Emerald Oil North America. The acquisition included approximately 10,600 net acres located in Dunn County, North Dakota and approximately 45,000 net acres in the Sand Wash Basin Niobrara shale oil play in northwestern Colorado and southwestern Wyoming.

The Emerald Oil North America acquisition was accounted for using the acquisition method. Assets acquired and liabilities assumed were recorded at their estimated fair values as of the acquisition date. The allocation of the purchase price is based upon a valuation of certain assets acquired and liabilities assumed. The Company recorded a gain on the bargain purchase of Emerald Oil North America as a result of the decrease in the Company’s share price between the announcement date (July 10, 2012) and closing date (July 26, 2012) of the acquisition in accordance with GAAP. A summary of the acquisition is below (in thousands):

F-12

Proved Oil and Natural Gas Properties	$	6,839
Unproved Oil and Natural Gas Properties		33,948
Other Assets		111
Debt Assumed		(20,303	)
Net Assets Acquired		20,595
Equity Issued to Emerald Oil NL		(13,381	)
Gain on Acquisition		7,214
Less: Acquisition Costs		(1,456	)
Gain on Acquisition, net	$	5,758

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 consolidated statements of operations from the closing date of the acquisition.  Purchase prices are allocated to acquired assets based on their estimated fair value at the time of the acquisition.  The Company has historically funded acquisitions with internal cash flow and the issuance of equity securities.

Acquisitions

On February 13, 2014, the Company acquired approximately 19,500 net acres located in Williams and McKenzie Counties, North Dakota from an unrelated third party for approximately $69.2 million in cash. Net daily production from the acreage was approximately 300 Boe/d as of January 1, 2014, the effective date of the transaction. The acquisition was accounted for as an asset purchase. Related transaction costs were capitalized to oil and natural gas properties.

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

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

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

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

F-13

Pro Forma Operating Results

In accordance with ASC Topic 805, presented below are unaudited pro forma results for the year ended December 31, 2014 and 2013 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:

	Year Ended December 31,
	2014			2013
Revenues	$	126,418,589		$	57,151,128
Net Loss Available to Common Stockholders	$	(48,179,709	)	$	(29,179,483	)
Net Loss Per Share – Basic and Diluted	$	(0.72	)	$	(0.71	)
Weighted Average Shares Outstanding – Basic and Diluted		66,772,458			41,383,277

Post-Acquisition Operating Results

The amount of revenues and excess of revenues over direct operating expenses included in the accompanying Consolidated Statements of Operations for the September 2014 acquisition is shown in the table that follows. Direct operating expenses include lease operating expenses, selling, general and administrative expenses and production and other taxes.

	Year Ended December 31,
	2014		2013
Revenues	$	2,590,658	$	—
Excess of revenues over direct operating expenses	$	1,299,829	$	—

Leasehold Sales

On March 28, 2013, the Company sold its undivided 45% working interest in and to certain oil and natural gas leaseholds in the Sand Wash Basin, comprising approximately 31,000 net acres located in Routt and Moffatt Counties, Colorado and Carbon County, Wyoming for an aggregate sale price of approximately $10.1 million in cash. No gain or loss was recognized as the sale did not significantly alter the relationship between capitalized costs and proved reserves. In December 2013, the Company sold its remaining oil and natural gas assets in the Sand Wash Basin, primarily comprised of 14,600 net acres in Routt County, Colorado to an unrelated third party for approximately $2.0 million.

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

F-14

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

On September 6, 2013, the Company sold its interest in 26,579 non-operated net acres located in the Williston Basin and the associated oil and natural gas production to an unrelated third party for a total sales price of approximately $111.0 million in cash, including sales price adjustments for development costs and production revenue and operating expenses during the effective period and subject to certain post-closing adjustments. $11.0 million of the sales price will remain in escrow upon finalization of standard due diligence procedures. On February 21, 2014, $8.6 million was released to Emerald, with the remaining $2.4 million returned to the buyer for purchase price adjustments during the due diligence period. The acreage was associated with non-operated working interests in Williston Basin Bakken and Three Forks wells. Under the full cost method of accounting for oil and natural gas operations, sales of oil and natural gas properties, whether or not being amortized, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to the cost center. The sale represented greater than 25 percent of the Company’s proved reserves of oil and natural gas attributable to the full cost pool. As a result, there was a significant alteration in the relationship between capitalized costs and proved reserves of oil and gas attributable to the full cost pool. Total capitalized costs within the full cost pool are allocated on the basis of the relative fair values of the properties sold and those retained due to substantial economic differences between the properties sold and those retained. Following this methodology, the following table represents a net sales price allocation of the transaction (in thousands):

Sale price	$	111,090
Add:  Disposition of asset retirement obligations		309
Less: Sale expenses		(1,168	)
Purchase price adjustments		(1,520	)
Sale price, net	$	108,711
Proved oil and natural gas properties	$	137,279
Accumulated depletion		(49,508	)
Unproved oil and natural gas properties		13,568
Gain on sale		7,372
Sale price, net	$	108,711

On September 2, 2014 the Company assigned approximately 4,300 net acres located in Williams County, North Dakota to an unrelated third party as partial consideration for an acquisition transaction. The fair value allocated to the acreage was approximately $35,918,000, including sales price adjustments for development costs and production revenue and operating expenses during the effective period. The acreage was associated with operated working interests in Williston Basin Bakken and Three Forks wells. No gain or loss was recognized as the sale did not significantly alter the relationship between capitalized costs and proved reserves.

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”), 5,114,633 shares of Series B Voting Preferred Stock (“Series B Preferred Stock”) and warrants to purchase an initial aggregate amount of 5,114,633 shares of the Company’s common stock at an initial exercise price of $5.77 per share, for an aggregate $50 million. Pursuant to the 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 Director 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.

F-15

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

NOTE 6  PREFERRED AND COMMON STOCK

Preferred Stock

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

On various dates throughout 2013, the Company redeemed all of the outstanding shares of Series A Preferred Stock, including principal of $50,000,000 and redemption premiums of $6,250,000, and no shares of Series A Preferred Stock remained outstanding as of December 31, 2014. For each redemption, the redemption premium was treated as a dividend and recorded as a return of equity to White Deer Energy through a charge to the Company’s additional paid-in capital. The Company paid no dividends during the year ended December 31, 2014 and $2,582,191 for the year ended December 31, 2013. No dividends were paid prior to 2013.

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

The warrants entitle White Deer Energy to acquire 5,114,633 shares of common stock at an initial exercise price of $5.77 per share and surrendering an equal number of shares of Series B Preferred Stock to the Company. In December 2014, the Company issued 10,721,824 common shares below the initial warrant exercise price of $5.77 to extinguish $21,000,000 of Convertible Notes. As a result of the issuance, the warrant exercise price was reduced to $3.02 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, Note 14 – Derivative Instruments and Price Risk Management – Warrant Liability and Note 16 – Subsequent Events for further discussion of the warrant liability valuation and further reduction of the warrant exercise price subsequent to year end.

Upon a change of control or Liquidation Event, as defined in the Securities Purchase Agreement, the Investor has the right, but not the obligation, to elect to receive from the Company, in exchange for all, but not less than all, shares of Series A and Series B Preferred Stock and the warrants issued pursuant to the Securities Purchase Agreement and shares of common stock issued upon exercise thereof that are then held by the Investor, an additional cash payment necessary to achieve a minimum internal rate of return of 25% as calculated as defined. The calculation took into account all cash inflows from and cash outflows to the Investor. Upon the final Series A Preferred Stock redemption on October 15, 2013, the minimum internal rate of return was achieved and no additional cash payment was necessary.

F-16

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 partial redemptions of preferred stock on June 20, 2013, August 30, 2013 and October 15, 2013. There was no issuance discount remaining as of December 31, 2013 or 2014.

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

	December 31, 2014		December 31, 2013		February 19, 2013 (issuance date)
Series A Preferred Stock	$	—	$	—	$	41,369,000
Series B Preferred Stock		5,000		5,000		5,000
Warrant Liability		2,199,000		15,703,000		8,626,000
Total	$	2,204,000	$	15,708,000	$	50,000,000

Equity Issuances

On February 8, 2011, the Company completed a private placement of 1,785,714 units, which consisted of one share of common stock and a warrant to purchase one-half of a share of common stock, at a subscription price of $28.00 per unit for total gross proceeds of $50 million. The exercise price of the warrants is $49.70 per whole share of common stock for a period of five years from the date of closing. The total number of shares that are issuable upon exercise of warrants is 892,857. The Company incurred costs of $3,397,749 related to this transaction, which costs were netted against the proceeds of the transaction through additional paid-in capital.

On September 28, 2012, the Company completed a public offering of 13,392,857 shares of common stock at a price of $5.60 per share for total gross proceeds of $75 million.  The Company incurred costs of approximately $5.3 million related to this transaction, which costs were netted against the proceeds of the transaction through additional paid-in capital. The underwriters elected to exercise the over-allotment option to sell an additional 484,698 shares of common stock at $5.60 per share. The gross proceeds from the over-allotment exercise were $2.7 million, and the net proceeds are approximately $2.5 million after deducting underwriting discounts and commissions. The over-allotment exercise closed on October 26, 2012.

The Company issued 851,315 and 313,700 shares of its common stock related to two acreage acquisitions completed on January 9, 2013 and February 4, 2013, respectively. See Note 4 – Oil and Natural Gas Properties – Acquisitions for additional details.

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

On June 4, 2013, the Company completed a private placement of 2,785,600 shares of common stock at a price of $5.87 per share for net proceeds of approximately $16.2 million after deducting placement agent fees of approximately $0.2 million. The Company’s Audit Committee, which consisted solely of independent directors, reviewed and approved this transaction. The issuance of the common stock was made in reliance upon an exemption from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(2) thereof, which exempts transactions by an issuer not involving any public offering.

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

F-17

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

In December 2014, the Company issued 10,721,824 common shares to extinguish $21,000,000 of Convertible Notes. As a result of the issuance, the warrant exercise price was reduced to $3.02 per share pursuant to a formula provided in the original warrant agreement. The Company recognized $10,438,080 of debt conversion expense for the fair value of the common shares issued in excess of the common shares underlying the original convertible note indenture agreement. See Note 9 – Convertible Notes and Note 16 – Subsequent Events for further discussion of the convertible notes.

Restricted Stock Awards and Restricted Stock Unit Awards

The Company incurred compensation expense associated with restricted stock and restricted stock units granted of $10,457,009, $10,903,696 and $4,684,009 for the years ended December 31, 2014, 2013 and 2012, respectively. There were 584,620 nonvested restricted stock units and $2,124,950 associated remaining unrecognized compensation expense as of December 31, 2014 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 of $1,641,664, $851,979 and $332,673 to oil and natural gas properties for the years ended December 31, 2014, 2013 and 2012, respectively. Approximately $919,633 of the compensation expense associated with restricted stock and restricted stock units during the year ended December 31, 2014 related to the modification and accelerated vesting of restricted stock unit grants associated with severance to a prior officer of the Company. A total of 213,228 restricted stock units associated with the severance vested on September 10, 2014. There is no remaining unamortized expense associated with the severance as of December 31, 2014. A summary of the restricted stock units and restricted stock shares outstanding is as follows:

	Number of Shares			Weighted Average Grant Date Fair Value
Non-vested restricted stock and restricted stock units at January 1, 2012		—		$	—
Granted		1,919,135			4.93
Canceled		—			—
Forfeited		(53,577	)		21.00
Vested		(17,857	)		21.00
Non-vested restricted stock and restricted stock units at December 31, 2012		1,847,701			4.31
Granted		1,242,505			7.10
Canceled		(70,642	)		4.19
Forfeited		(302,016	)		4.86
Vested		(635,361	)		4.88
Non-vested restricted stock and restricted stock units at December 31, 2013		2,082,187			5.73
Granted		264,134			7.48
Canceled		(73,204	)		7.23
Forfeited		(639,299	)		5.48
Vested		(1,049,198	)		5.36
Non-vested restricted stock and restricted stock units at December 31, 2014		584,620		$	7.27

F-18

NOTE 7  STOCK OPTIONS AND WARRANTS

Stock Options

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

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

On July 1, 2014, the Company granted stock options to certain employees to purchase a total of 7,700 shares of common stock exercisable at $7.65 per share. The options vest on an annual basis over 36 months with 2,566 options vesting on July 1, 2015, 2016 and 2017.

On September 22, 2014, the Company granted stock options to certain employees to purchase a total of 19,000 shares of common stock exercisable at $6.80 per share. The options vest on an annual basis over 36 months with 6,333 options vesting on September 22, 2015, 2016 and 2017.

On October 1, 2014 the Company granted stock options to certain employees to purchase a total of 3,400 shares of common stock exercisable at $6.15 per share. The options vest on an annual basis over 36 months with 1,133 options vesting on September 30, 2015, 2016 and 2017.

The total fair value of all stock options granted during the years ended December 31, 2014, 2013 and 2012 were calculated using the Black-Scholes valuation model based on factors present at the time the options were granted.

The impact on the Company’s statement of operations of stock-based compensation expense related to options granted for the years ended December 31, 2014, 2013, and 2012 was $894,303, $1,600,924 and $2,634,681, respectively, net of $0 tax. The Company capitalized $631,992, $1,193,960 and $249,367 in compensation to oil and natural gas properties related to outstanding options for the years ended December 31, 2014, 2013 and 2012, respectively.

A summary of options for the years ended December 31, 2014, 2013, and 2012 is as follows:

	Number of Options			Weighted Average Exercise Price		Remaining Contractual Term (in Years)		Intrinsic Value
Outstanding at January 1, 2012		150,000		$	20.44		7.2		—
Granted		685,713			8.11		—		—
Exercised		—			—		—		—
Forfeited or Expired		—			—		—		—
Outstanding at December 31, 2012		835,713			10.43		7.7		—
Granted		505,301			7.18		—		—
Exercised		(75,000	)		4.43		—		—
Forfeited or Expired		(107,143	)		16.54		—		—
Outstanding at December 31, 2013		1,158,871			8.90		4.8		—
Granted		581,399			7.11		—		—
Exercised		(75,000	)		4.43		—		—
Forfeited or Expired		(470,591	)		8.26		—		—
Outstanding at December 31, 2014		1,194,679		$	8.56		3.7	$	—
Stock Options Exercisable at December 31, 2012		424,997		$	11.39		5.9	$	121,500
Stock Options Exercisable at December 31, 2013		464,273		$	11.12		3.1	$	356,024
Stock Options Exercisable at December 31, 2014		562,673		$	10.03		2.8	$	—

F-19

A summary of the status of the Company’s nonvested options as of December 31, 2014 and changes during the year then ended is as follows:

	Number of Options			Weighted-Average Grant-Date Fair Value
Nonvested at December 31, 2012		410,716		$	5.87
Granted		505,301			7.18
Vested		(200,000	)		10.47
Forfeited		(21,430			12.39
Nonvested at December 31, 2013		694,587			7.41
Granted		581,399			7.48
Vested		(373,024	)		7.43
Forfeited		(270,956	)		7.12
Nonvested at December 31, 2014		632,006		$	6.91

For the year ended December 31, 2014, 2013 and 2012, other information pertaining to stock options was as follows:

	2014		2013		2012
Weighted-average per share grant-date fair value of stock options granted	$	7.11	$	4.43	$	4.62
Total intrinsic value of options exercised		257,250		211,250		—
Total grant-date fair value of stock options vested during the year		1,557,619		2,093,999		2,159,307

The following assumptions were used for the Black-Scholes model to value the options granted during the years ended December 31, 2014, 2013 and 2012.

	2014	2013	2012
Risk free rates	0.58% to 1.42%	0.48% to 2.12%	0.17% to 1.20%
Dividend Yield	0%	0%	0%
Expected volatility	56.16% to 67.70%	64.64% to 79.50%	69.70% to 78.99%
Weighted average expected life	3.5 years	5 years	4 years

F-20

There was $923,614 of total unrecognized compensation cost related to nonvested stock options granted as of December 31, 2014. At December 31, 2014, the remaining cost is expected to be recognized over a weighted-average period of 0.91 years. These estimates are subject to change based on a variety of future events which include, but are not limited to, changes in estimated forfeiture rates, cancellations and the issuance of new options.

Warrants

The Company has recognized no stock-based compensation expense related to warrants granted for the years ended December 31, 2014, 2013, and 2012. A summary of warrants granted to employees, directors and consultants for the years ended December 31, 2014, 2013 and 2012 is as follows:

	Number of Warrants		Weighted Average Exercise Price		Remaining Contractual Term (in Years)		Intrinsic Value
Outstanding at December 31, 2011		223,293	$	6.86		8.0	$	2,458,251
Granted		—		—		—		—
Exercised		—		—		—		—
Outstanding at December 31, 2012		223,293		6.86		7.0		—
Granted		—		—		—		—
Exercised		—		—		—		—
Outstanding at December 31, 2013		223,293		6.86		6.0		178,634
Granted		—		—		—		—
Exercised		—		—		—		—
Outstanding at December 31, 2014		223,293	$	6.86		5.0	$	—

On February 8, 2011, in conjunction with the sale of 1,785,714 shares of common stock (see Note 6), the Company issued investors warrants to purchase a total of 892,858 shares of common stock exercisable at $49.70 per share.

For the years ended December 31, 2014, 2013 and 2012, other information pertaining to warrants was as follows:

	2014		2013 (1)		2012
Weighted-average grant-date fair value of warrants granted	$	—	$	1.69	$	—
Total intrinsic value of warrants exercised	$	—	$	—	$	—
Total grant-date fair value of warrants vested during the year	$	—	$	—	$	—

(1) See Note 6 – Common and Preferred Stock – Preferred Stock for details on the warrants issued on February 19, 2013 associated with the preferred stock transaction.

F-21

The following assumptions were used for the Black-Scholes model to value the warrants granted during the years ended December 31, 2014, 2013 and 2012.

	2014		2013 (1)		2012
Risk free rates		—		—		—
Dividend yield		—		—		—
Expected volatility		—		—		—
Weighted average expected life		—		—		—

(1) See Note 14 – Derivative Instruments and Price Risk Management – Warrant Liability for the method and assumptions used to value the warrants issued on February 19, 2013 associated with the preferred stock transaction.

The table below reflects the status of warrants outstanding at December 31, 2014:

	Warrants		Exercise Price		Expiration Date
December 1, 2009		37,216	$	6.86	December 1, 2019
December 31, 2009		186,077	$	6.86	December 31, 2019
February 8, 2011		892,858	$	49.70	February 8, 2016
February 19, 2013 (1)		5,114,633	$	3.02	December 31, 2019
Total		6,230,784

(1) See Note 16 – Subsequent Events for details on the warrant price adjustment subsequent to December 31, 2014.

No warrants expired or were forfeited during the year ended December 31, 2014. All of the compensation expense related to the applicable vested warrants issued to employees has been expensed by the Company prior to 2012. All warrants outstanding were exercisable at December 31, 2014.

NOTE 8 REVOLVING CREDIT FACILITY

Wells Fargo Facility

On November 20, 2012, the Company entered into a senior secured revolving credit facility (the “Credit Facility”) with Wells Fargo Bank, N.A., as administrative agent (“Wells Fargo”), and the lenders party thereto. The Credit Facility is a senior secured reserve-based revolving credit facility with a maximum commitment of $400 million. As of December 31, 2014, the Company had drawn $75.0 million toward its $250 million borrowing base under the Credit Facility.

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

The annual interest cost under the Credit Facility, which is dependent upon the percentage of the borrowing base utilized, is, at the Company’s option, based on either the Alternate Base Rate (as defined under the terms of the Credit Facility) plus 0.75% to 1.75% or the London Interbank Offer Rate (LIBOR) plus 1.75% to 2.75%; provided, in no event may the interest rate exceed the maximum interest rate allowed by any current or future law.  Interest on ABR Loans is due and payable on a quarterly basis, and interest on Eurodollar Loans is due and payable, at the Company’s option, at one-, two-, three-, six- (or in some cases nine- or twelve-) month intervals. The Company also pays a commitment fee ranging from 0.375% to 0.5%, depending on the percentage of the borrowing base utilized. As of December 31, 2014, the annual interest rate on the Credit Facility was 3.16%.

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 December 31, 2014, the Company has not obtained any letters of credit under the Credit Facility.

F-22

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

The Credit Facility contains customary covenants that include, among other things: limitations on the ability of the Company to incur or guarantee additional indebtedness; create liens; pay dividends on or repurchase stock; make certain types of investments; enter into transactions with affiliates; and sell assets or merge with other companies. The Credit Facility also requires compliance with certain financial covenants, including, (a) a ratio of current assets to current liabilities of at least 1.00 to 1.00, (b) a maximum ratio of total debt to EBITDA for the preceding four fiscal quarters of no more than 4.00 to 1.00. For any fiscal quarter ending in calendar year 2014, total debt is reduced by cash equivalents less $10,000,000 for purposes of calculating the total debt to EBITDA ratio. The Company was in compliance with all covenants under the Credit Facility as of December 31, 2014.

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

NOTE 9 CONVERTIBLE NOTES

On March 24, 2014, the Company completed a private placement of $172.5 million in aggregate principal amount of 2.0% Convertible Notes (the “Convertible Notes”), and entered into an indenture (the “Indenture”) governing the Convertible Notes, with U.S. Bank National Association, as trustee (the “Trustee”). The Convertible Notes accrue interest at a rate of 2.00% per year, payable semiannually in arrears on April 1 and October 1 of each year, beginning on October 1, 2014. The Convertible Notes mature on April 1, 2019. The Convertible Notes are the Company’s unsecured senior obligations and are equal in right of payment to the Company’s existing and future senior indebtedness. The Convertible Notes were convertible into approximately 17,264,958 shares of common stock as of December 31, 2014. However, the Company does not believe further conversion will take place due to the term remaining on the Convertible Notes, and in the event of conversion, holders would forgo all future interest payments. As a result, the Convertible Notes have been classified as long-term debt as of December 31, 2014.

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

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

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

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

F-23

The Indenture contains customary terms and covenants and events of default. If an Event of Default (as defined in the Indenture) occurs and is continuing, the Trustee or the holders of at least 25% in aggregate principal amount of the then outstanding Convertible Notes may declare by written notice all the Convertible Notes to be immediately due and payable in full. The Company was in compliance with all covenants as of December 31, 2014.

In December 2014, the Company issued 10,721,824 common shares to extinguish $21,000,000 of Convertible Notes. The Convertible Notes had 2,393,162 underlying common shares under the terms of the original indenture agreement. As a result, the Company recognized $10,438,080 of debt conversion expense for the fair value of the common shares issued in excess of the common shares underlying the original convertible note indenture agreement.

NOTE 10  ASSET RETIREMENT OBLIGATION

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

The following table summarizes the Company’s asset retirement obligation transactions for the years ended December 31, 2014, 2013 and 2012:

	2014			2013			2012
Beginning Asset Retirement Obligation	$	692,137		$	296,074		$	116,119
Revision of Previous Estimates		148,968			165,968			—
Liabilities Incurred or Acquired		1,817,939			510,271			164,967
Accretion of Discount on Asset Retirement Obligations		104,803			32,449			14,988
Wells Settled through P&A		(72,555	)		—			—
Liabilities Associated with Properties Sold		(19,317	)		(312,625	)		—
Ending Asset Retirement Obligation	$	2,671,975		$	692,137		$	296,074

NOTE 11 ACCRUED LIABILITIES

The Company’s accrued liabilities consist of the following:

	December 31,
	2014		2013
Accrued Transaction Adjustments	$	249,764	$	2,067,150
Oil and Natural Gas Revenue Payable		4,667,935		7,451,394
Other General and Administrative Expenses		6,350,132		2,303,185
Total Accrued Liabilities	$	11,267,831	$	11,821,729

F-24

NOTE 12  INCOME TAXES

The Company utilizes the asset and liability approach to measuring deferred tax assets and liabilities based on temporary differences existing at each balance sheet date using currently enacted tax rates in accordance with ASC 740-10-30. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment.

The income tax expense (benefit) for the year ended December 31, 2014, 2013, and 2012 consists of the following:

	2014		2013		2012
Current Income Taxes	$	—	$	—	$	—
Deferred Income Taxes
Federal		—		—		—
State		—		—		—
Total Benefit	$	—	$	—	$	—

The following is a reconciliation of the reported amount of income tax expense (benefit) for the years ended December 31, 2014, 2013 and 2012 to the amount of income tax expenses that would result from applying the statutory rate to pretax income.

Reconciliation of reported amount of income tax expense:

	2014			2013			2012
Loss Before Taxes	$	(52,145,225	)	$	(10,882,895	)	$	(62,296,099	)
Federal Statutory Rate		35	%		35	%		35	%
Benefit Computed at Federal Statutory Rates		(18,250,829	)		(3,809,013	)		(21,803,635	)
State Benefit, Net of Federal Benefit		(923,445	)		(102,503	)		(1,969,364	)
Effects of:
Warrant Revaluation		(4,726,400	)		2,476,950			—
Debt Conversion Expense		3,653,328			—			—
Cancellation of Debt Income		2,646,473			—			—
Nondeductible Expenses		21,155			366,203			10,941
Other		(30,466	)		125,956			(119,872	)
Change in Valuation Allowance		17,610,184			942,407			23,881,930
Reported Benefit	$	—		$	—		$	—

F-25

The components of the Company’s deferred tax asset were as follows:

	Year Ended December 31,
	2014			2013
Deferred Tax Assets:
Net Operating Loss Carryforwards (NOLs)	$	41,697,116		$	36,382,177
Stock-based Compensation		5,023,270			3,245,308
Accrued Liability		1,595,333			—
Derivatives		—			323,190
Equity Investments		—			116,886
Oil and Natural Gas Properties		194,329			—
Total Deferred Tax Assets		48,510,048			40,067,561
Deferred Tax Liabilities:		—
Oil and Natural Gas Properties		—			11,093,181
Derivatives		1,877,126			—
Other		55,711			7,353
Total Deferred Tax Liabilities		1,932,837			11,100,534
Less: Valuation Allowance		(46,577,211	)		(28,967,027	)
Total Net Deferred Tax Asset	$	—		$	—

At December 31, 2014, the Company had U.S. Federal NOL carryovers of approximately $117,404,000 which expire from 2029 through 2034. In addition, the Company had state NOL carryovers of approximately $93,502,000, which expire from 2016 through 2034. During 2012, the Company had a IRC Section 382 change of ownership. As a result of the ownership change, the Company's utilization of pre-change U.S. Federal NOL's are subject to an annual limitation amount of approximately $1,754,000. Valuation allowances of $46,577,000 and $28,967,000 have been established to offset the Company's net deferred tax assets as of December 31, 2014 and December 31, 2013, respectively, as the realization of these deferred tax assets is not more likely than not.

Tax benefits are recognized only for tax positions that are more likely than not to be sustained upon examination by tax authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50 percent likely to be realized upon ultimate settlement. Unrecognized tax benefits are tax benefits claimed in the Company's tax returns that do not meet these recognition and measurement standards. The Company has no liabilities for unrecognized tax benefits.

The Company's policy is to recognize potential interest and penalties accrued related to unrecognized tax benefits within income tax expenses. For the years ended December 31, 2014, 2013 and 2012, the Company did not recognize any interest or penalties in its statement of operations, nor did it have any interest or penalties accrued in its balance sheet at December 31, 2014 and 2013 relating to unrecognized benefits.

The tax years 2011 through 2014 remain open to examination for U.S. federal income tax purposes. The Company files tax returns with various state taxing authorities and these returns remain open to examination for the tax years 2010 through 2014.

NOTE 13 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.

F-26

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

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

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

Fair Value on a Recurring Basis

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

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

F-27

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

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

Level 2 assets consist of commodity derivative assets and liabilities (see Note 14 – Derivative Instruments and Price Risk Management).  The fair value of the commodity derivative assets and liabilities are estimated by the Company using the income valuation techniques utilizing an option pricing or discounted cash flow model, as appropriate, which take into account notional quantities, market volatility, market prices, contract parameters and discount rates based on published LIBOR rates. The Company validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those securities trade in active markets.  Assumed credit risk adjustments, based on published credit ratings, public bond yield spreads and credit default swap spreads, are applied to the Company’s commodity derivatives. Significant changes in the quoted forward prices for commodities and changes in market volatility generally leads to corresponding changes in the fair value measurement of the Company’s oil derivative contracts. The fair value of all derivative contracts is reflected on the consolidated balance sheets.

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

Balance, at December 31, 2013	$	(15,703,000	)
Purchases, issuances, and settlements		—
Change in Fair Value of Warrant Liability		13,504,000
Transfers		—
Balance, at December 31, 2014	$	(2,199,000	)

The fair value of the warrants upon issuance to White Deer Energy on February 19, 2013 was recorded at $8,626,000. The warrant revaluation gain (expense) was $13,504,000 and $(7,077,000) for the year ended December 31, 2014 and 2013, respectively, and is included in Other Income/Expense on the accompanying Consolidated Statements of Operations. See discussion of assumptions used in valuing the warrants at Note 14 – 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, 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 $81.8 million at December 31, 2014 based on observed prices for the same or similar types of debt instruments. The Company has classified the valuations of the Convertible Notes and Credit Facility under Level 2 of the fair value hierarchy.

F-28

NOTE 14 DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT

Commodity

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

All derivative positions are carried at their fair value on the 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 and therefore the current asset and liability are netted on the consolidated balance sheet and the non-current asset and liability are netted on the consolidated balance sheet.

The following table reflects open commodity swap contracts as of December 31, 2014, the associated volumes and the corresponding weighted average NYMEX reference price:

Settlement Period	Oil (Bbls)		Fixed Price
Oil Swaps
January 1, 2015 – March 31, 2015		30,000	$	93.50
January 1, 2015 – March 31, 2015		36,000		96.05
January 1, 2015 – March 31, 2015		21,000		97.00
January 1, 2015 – March 31, 2015		33,000		97.50
2015 Total/Average		120,000	$	95.98

On January 5, 2015, the company settled its outstanding NYMEX West Texas Intermediate oil derivative swap contracts on a total of 120,000 barrels of oil, resulting in a cash settlement received of $5,317,300.

The following table sets forth a reconciliation of the changes in fair value of the Company’s commodity derivatives for the years ended December 31, 2014 and 2013.

	2014			2013
Beginning fair value of commodity derivatives	$	(853,005	)	$	(181,248	)
Total gains (losses) on oil derivatives		11,439,240			(2,656,535	)
Cash settlements (received) paid on oil derivatives		(5,542,110	)		1,984,778
Ending fair value of commodity derivatives	$	5,044,125		$	(853,005	)

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

Warrant Liability

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

F-29

The Company estimated the value of the warrants issued with the Securities Purchase Agreement on the date of issuance to be $8,626,000, or $1.69 per warrant, using the Monte Carlo model with the following assumptions: a term of 1,798 trading days, exercise price of $5.77, volatility rate of 40%, and a risk-free interest rate of 1.38%. The Company remeasured the warrants as of December 31, 2014, using the same Monte Carlo model, using the following assumptions: a term of 1,255 trading days, exercise price of $3.02, stock price of $1.20, average volatility rate of 61%, and a risk-free interest rate of 1.65%. As of December 31, 2014, the fair value of the warrants was $2,199,000, or $0.43 per warrant, and was recorded as a liability on the accompanying consolidated balance sheets. An increase in any of the variables would cause an increase in the fair value of the warrants. Likewise, a decrease in any variable would cause a decrease in the value of the warrants.

At December 31, 2014, the Company had derivative financial instruments recorded on the consolidated balance sheet as set forth below:

Type of Contract	Balance Sheet Location
Derivative Assets (Liabilities):
Swap Contracts	Current assets	$	5,044,125
Warrant Liability	Non-current liabilities		(2,199,000	)
Total Derivative Liabilities		$	2,845,125

At December 31, 2013, the Company had derivative financial instruments recorded on the consolidated balance sheet as set forth below:

Type of Contract	Balance Sheet Location
Derivative Assets (Liabilities):
Swap Contracts	Current liabilities	$	(921,401	)
Swap Contracts	Non-current assets		68,396
Warrant Liability	Non-current liabilities		(15,703,000	)
Total Derivative Liabilities		$	(16,556,005	)

NOTE 15 COMMITMENTS AND CONTINGENCIES

The Company conducts the majority of its operations in leased facilities, which are accounted for as operating leases. Generally, the leases provide that the Company pays a base rent plus all insurance, maintenance and all other costs and expenses associated with the use of the buildings. Additionally, on some leases the Company pays a portion or all of the property taxes on the premises.

Total rent expenses for leased facilities and other equipment rentals were approximately $362,873, $399,382 and $115,659 for the years ended December 31, 2014, 2013 and 2012, respectively.

At December 31, 2014, the minimum rental commitments under all non-cancelable operating leases with initial or remaining terms of more than one year are as follows:

F-30

	Payment due for the year ended December 31,
Contractual Obligations	Total		2015		2016		2017		2018		2019
Office Leases (1)	$	2,320,441	$	464,088	$	472,630	$	481,171	$	489,713	$	412,839

(1) The Denver, Colorado office lease commenced on December 15, 2012 and, as amended, has a term of 66 months, expiring in October 2019.

As is customary in the oil and natural gas industry, the Company may at times have commitments in place to reserve or earn certain acreage positions or wells. If the Company does not meet such commitments, the acreage positions or wells may be lost.

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

NOTE 16 SUBSEQUENT EVENTS

Equity Offering

On February 11, 2015, the Company completed a public offering of 24,553,571 shares of common stock at a price of $1.12 per share for total net proceeds of approximately $26.5 million. On February 19, 2015 the underwriters elected to exercise the over-allotment option to sell an additional 2,605,536 shares of common stock at $1.12 per share. The net proceeds from the over-allotment exercise were $2.8 million.

Warrant Exercise Price Adjustment

As a result of the sale of common shares completed on February 11, 2015, the outstanding warrants held by White Deer were adjusted from the December 31, 2014 exercise price of $3.02 to $2.05 per share pursuant to a formula provided in the original warrant agreement.

Derivative Instruments

On January 6, 2015, the Company settled outstanding NYMEX West Texas Intermediate oil derivative swap contracts on a total of 120,000 barrels of oil, resulting in a cash settlement received of $5,317,300, as indicated below:

Settlement Period	Oil (Bbls)		Settlement Price		Cover Price		Cash Settlement
January 1, 2015 – March 31, 2015		30,000		93.50		51.67		1,255,000
January 1, 2015 – March 31, 2015		36,000		96.05		51.67		1,597,800
January 1, 2015 – March 31, 2015		21,000		97.00		51.67		952,000
January 1, 2015 – March 31, 2015		33,000		97.50		51.67		1,512,500
Total		120,000	$	95.98	$	51.67	$	5,317,300

F-31

NOTE 17  QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)

Quarterly data for the years ended December 31, 2014 and 2013 are as follows:

	For the Year Ended December 31, 2014
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Total Revenue	$	18,270,019		$	24,591,325		$	39,911,905		$	29,834,582
Expenses	$	19,556,696		$	23,634,370		$	24,915,171		$	95,069,358
Income (Loss) from Operations	$	(1,286,677	)	$	956,955		$	14,996,734		$	(65,234,776	)
Other Income (Expense), Net	$	(364,410	)	$	(2,907,006	)	$	(1,337,659	)	$	3,031,614
Net Income (Loss) (1)	$	(1,651,087	)	$	(1,950,051	)	$	13,659,075		$	(62,206,162	)
Net Cash Provided By (Used For) Operating Activities	$	10,227,413		$	9,667,326		$	21,301,731		$	15,634,413
Net Cash Provided (Used in) Investing Activities	$	(125,606,786	)	$	(70,850,715	)	$	(277,674,077	)	$	44,863,482
Net Cash Provided (Used in) Financing Activities	$	167,086,647		$	(607,656	)	$	186,469,141		$	(112,377,127	)

(1) The Company recorded impairment of the net capitalized costs of its oil and natural gas properties in the amount of $66,430,000 and debt conversion expense for the fair value of the common shares issued in excess of the common shares underlying the original convertible note indenture agreement in the amount of $10,438,080 in the fourth quarter of 2014.

	For the Year Ended December 31, 2013
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Total Revenue	$	7,449,377		$	11,240,155		$	14,596,398		$	18,038,575
Expenses	$	10,316,386		$	12,248,325		$	5,813,788		$	26,466,746
Income (Loss) from Operations	$	(2,867,009	)	$	(1,008,170	)	$	8,782,610		$	(8,428,171	)
Other Income (Expense), Net	$	(3,617,814	)	$	(714,964	)	$	(524,105	)	$	(2,505,272	)
Net Income (Loss)	$	(6,484,823	)	$	(1,723,134	)	$	8,258,505		$	(10,933,443	)
Net Loss Attributable to Common Stockholders	$	(7,101,261	)	$	(7,388,804	)	$	(5,738,584	)	$	(10,933,443	)
Net Cash Provided By (Used For) Operating Activities	$	377,822		$	1,838,477		$	7,322,429		$	(3,348,288	)
Net Cash Provided (Used in) Investing Activities	$	(13,019,732	)	$	(27,662,815	)	$	12,954,748		$	(47,272,739	)
Net Cash Provided By (Used In) Financing Activities	$	38,243,906		$	62,720,981		$	(23,440,287	)	$	125,348,557

F-32

SUPPLEMENTAL OIL AND NATURAL GAS INFORMATION

Oil and Natural Gas Reserves and Related Financial Data (Unaudited)

The reserves at December 31, 2014, 2013 and 2012 presented below were prepared by the independent engineering firm, Netherland, Sewell & Associates, Inc. All reserves are located within the continental United States. Proved oil and natural gas reserves are the estimated quantities of oil and natural gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions (i.e., prices and costs) existing at the time the estimate is made. Proved developed oil and natural gas reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made. Proved undeveloped reserves are included for reserves for which there is a high degree of confidence in their recoverability and they are scheduled to be drilled within the next five years. A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are decline curve analysis, advance production type curve matching, petro-physics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.

Oil and Natural Gas Reserve Data (Unaudited)

The following tables present the Company’s estimates of its proved oil and natural gas reserves. The Company emphasizes that reserves are approximations and are expected to change as additional information becomes available. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.

	Natural Gas (MCF)			Oil (BLS)
Proved Developed and Undeveloped Reserves at December 31, 2011		1,739,043			3,227,021
Revisions of Previous Estimates		(1,225,387	)		(2,738,676	)
Extensions, Discoveries and Other Additions		841,310			1,808,282
Acquisition of Reserves		1,680,618			2,892,866
Production		(127,091	)		(320,147	)
Proved Developed and Undeveloped Reserves at December 31, 2012		2,908,493			4,869,346
Revisions of Previous Estimates		1,076,375			1,151,278
Extensions, Discoveries and Other Additions		7,998,010			10,325,814
Acquisition of Reserves		925,229			459,088
Divestiture of Reserves		(2,694,348	)		(4,649,098	)
Production		(211,608	)		(580,797	)
Proved Developed and Undeveloped Reserves at December 31, 2013		10,002,151			11,575,631
Revisions of Previous Estimates		(3,454,454	)		(4,080,514	)
Extensions, Discoveries and Other Additions		11,684,627			14,504,337
Acquisition of Reserves		3,176,120			2,065,633
Divestiture of Reserves		—			—
Production		(338,536	)		(1,238,807	)
Proved Developed and Undeveloped Reserves at December 31, 2014		21,069,908			22,826,280
Proved Developed Reserves:
Proved Developed Reserves at December 31, 2011		410,092			1,066,504
Proved Developed Reserves at December 31, 2012		1,014,158			1,788,230
Proved Developed Reserves at December 31, 2013		5,770,651			5,810,932
Proved Developed Reserves at December 31, 2014		11,670,507			13,194,100
Proved Undeveloped Reserves:
Proved Undeveloped Reserves at December 31, 2011		1,328,953			2,160,518
Proved Undeveloped Reserves at December 31, 2012		1,894,335			3,081,116
Proved Undeveloped Reserves at December 31, 2013		4,231,500			5,764,700
Proved Undeveloped Reserves at December 31, 2014		9,399,400			9,632,100

F-33

Oil and natural gas sales reflect the market prices of net production sold or transferred with appropriate adjustments for royalties, net profits interest, and other contractual provisions. Production expenses include lifting costs incurred to operate and maintain productive wells and related equipment including such costs as operating labor, repairs and maintenance, materials, supplies and fuel consumed. Production taxes include production and severance taxes. Depletion of oil and natural gas properties relates to capitalized costs incurred in acquisition, exploration, and development activities. Results of operations do not include interest expense and general corporate amounts. The results of operations for the Company’s oil and natural gas production activities are provided in the Company’s related statements of operations.

During 2014, the Company acquired approximately 2,000 MBoe in proved reserves in McKenzie and Dunn Counties of North Dakota in the Williston Basin. As a result of the Company's active development programs in these areas, the Company added 10,600 MBoe.

The Company's reserves have been estimated using deterministic methods. The total proved reserve additions of 16,958 Mboe are comprised of 7,678 MBoe in proved developed and 9,280 MBoe in proved undeveloped reserves, all from the Williston Basin.

At December 31, 2014, our estimated proved undeveloped (PUD) reserves were approximately 11,199 MBoe, a 4,729 MBoe net increase over the previous year's estimate of 6,470 MBoe. The increase is largely due to extensions and discoveries net of transfers to proved developed reserves and divestitures totaling 7,294 MBoe, offset in part by revisions in quantity estimates, all of which were incurred in the Williston Basin. As of December 31, 2014, all of our PUD reserves are less than five years old. The following details the changes in proved undeveloped reserves for 2014 (MBoe):

Beginning proved undeveloped reserves at December 31, 2013	6,470
Undeveloped reserves transferred to developed	(1,986	)
Revisions	(2,565	)
Purchases	—
Divestitures	—
Extensions and discoveries	9,280
Ending proved undeveloped reserves at December 31, 2013	11,199

Standardized Measure of Discounted Future Net Cash Inflows and Changes Therein (Unaudited)

The following table presents a standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves and the changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas were prepared in accordance with the provisions of ASC 932-235-555 (formerly SFAS 69). Future cash inflows were computed by applying average prices of oil and natural gas for the last 12 months as of December 31, 2014 to estimated future production. Future production and development costs were computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. Future income tax expenses were calculated by applying appropriate year-end tax rates to future pretax cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved and tax credits and loss carryforwards relating to oil and natural gas producing activities. Future net cash flows are discounted at the rate of 10% annually to derive the standardized measure of discounted future cash flows. Actual future cash inflows may vary considerably, and the standardized measure does not necessarily represent the fair value of the Company’s oil and natural gas reserves.

F-34

	Years Ended December 31,
	2014			2013			2012
Future Cash Inflows	$	2,025,904,900		$	1,089,605,300		$	432,483,781
Future Production Costs		(665,421,600	)		(375,569,800	)		(135,774,945	)
Future Development Costs		(238,150,500	)		(199,190,700	)		(93,833,711	)
Future Income Taxes		(216,303,139	)		(100,550,387	)		(12,157,129	)
Future Net Cash Inflows		906,029,661			414,294,413			190,717,996
10% Annual Discount for Estimated Timing of Cash Flows		(461,714,255	)		(215,922,945	)		(105,433,212	)
Standardized Measure of Discounted Future Net Cash Flows	$	444,315,406		$	198,371,468		$	85,284,784

The twelve month average prices for the year ended December 31, 2014 was adjusted to reflect applicable transportation and quality differentials on a well-by-well basis to arrive at realized sales prices used to estimate the Company’s reserves. The prices for the Company’s reserve estimates were as follows:

	Natural Gas MCF		Oil Bbl
December 31, 2014	$	7.66	$	81.68
December 31, 2013	$	6.17	$	88.80
December 31, 2012	$	5.13	$	85.75

Changes in the future net cash inflows discounted at 10% per annum follow:

	Years Ended December 31,
	2014			2013			2012
Beginning of Period	$	198,371,468		$	85,284,784		$	59,625,002
Sales of Oil and Natural Gas Produced, Net of Production Costs		(80,609,167	)		(39,758,105	)		(22,447,837	)
Extensions and Discoveries		259,824,704			209,815,976			38,895,353
Previously Estimated Development Cost Incurred During the Period		78,551,062			12,701,839			11,482,616
Net Change of Prices and Production Costs		(49,065,792	)		5,851,285	)		(3,003,652
Change in Future Development Costs		85,634,722			(19,060,290	)		(13,726,678	)
Revisions of Quantity and Timing Estimates		(83,480,119	)		62,461,641	)		(30,431,352
Accretion of Discount		23,742,220			8,781,936			5,962,520
Change in Income Taxes		(51,720,461	)		(36,516,157	)		(2,534,578
Purchase of Reserves in Place		53,689,865			21,433,173			31,348,048
Divestiture of Reserves in Place		—			(122,297,882			—
Changes in timing and other		9,376,904			9,673,268			10,115,342
	$	444,315,406		$	198,371,468		$	85,284,784

F-35

Costs Incurred and Capitalized Costs

The costs incurred in oil and natural gas acquisition, exploration and development activities follow:

	Year Ended December 31,
	2014		2013		2012
Proved Property Acquisition	$	81,617,127	$	10,373,374	$	7,799,945
Unproved Property Acquisition		129,814,654		56,297,987		54,917,350
Exploration Costs		85,709,932		81,650,325		1,939,440
Development		231,164,196		64,355,298		71,811,058
Total	$	528,305,909	$	212,676,984	$	136,467,793

Excluded costs for unproved properties are accumulated by year. Costs are reflected in the full cost pool as the drilling costs are incurred or as costs are evaluated and deemed impaired. The Company anticipates these excluded costs will be included in the depletion computation over the next five years. The Company is unable to predict the future impact on depletion rates. The following is a summary of capitalized costs excluded from depletion at December 31, 2014 by year incurred.

	Year Ended December 31,
	Total		2014		2013		2012		Prior Years
Property Acquisition	$	157,315,588	$	120,429,854	$	27,160,938	$	3,578,212	$	6,146,584
Exploration		1,342,317		1,342,317		—		—		—
Drilling		8,050,358		8,050,358		—		—		—
Total	$	166,708,263	$	129,822,529	$	27,160,938	$	3,578,212	$	6,146,584

F-36

EX-12.1

EXHIBIT 12.1

EMERALD OIL, INC.

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

	Year Ended December 31,
	2010			2011			2012			2013			2014
Earnings
Net loss before income taxes	$	(4,268,569	)	$	(1,345,054	)	$	(62,296,099	)	$	(10,882,895	)	$	(52,145,225	)
Add: Income taxes		65,240			—			—			—			—
Add: Fixed charges		630,603			2,037,552			2,623,122			323,282			4,708,530
Total earnings		(3,572,726	)		692,498			(59,672,978	)		(10,559,613	)		(47,436,695	)
Fixed charges
Interest expense		629,026			2,036,032			2,614,240			287,934			4,675,475
Rental expense attributable to interest		1,577			1,520			8,882			35,348			33,055
Total fixed charges		630,603			2,037,552			2,623,122			323,282			4,708,530
Ratio of earnings to fixed charges		—	(2)		0.34			—	(2)		—	(2)		—	(2)
Deficiency ($)	$	4,203,329		$	1,345,054		$	62,296,099		$	10,882,895		$	52,145,225
Preferred stock dividends (1)		—			—			—			20,279,197			—
Ratio of earnings to fixed charges plus preferred stock dividends (1)		—			—			—			—	(2)		—
Deficiency ($)										$	31,162,092

(1) For the purposes of determining the ratio of earnings to fixed charges and the ratio of earnings to fixed charges plus preferred stock dividends, earnings are defined as net income before income taxes, amortization of capitalized interest, rent expense, and interest expense. Fixed charges consist of interest expense and rent expense attributable to interest. Preferred stock dividends are dividends paid on our Series A Perpetual Preferred Stock issued on February 19, 2013, the remaining shares of which were redeemed in full on October 15, 2013. Earnings were insufficient to cover the fixed charges plus preferred stock dividends by approximately $31.1 million for the year ended December 31, 2013.

(2) Earnings were insufficient to cover fixed charges.

EX-21.1

EXHIBIT 21.1

EMERALD OIL, INC.

SUBSIDIARIES

Name of Subsidiary	Jurisdiction of Incorporation or Organization
Emerald WB LLC	Colorado
EOX Marketing LLC	Delaware

EX-23.1

EXHIBIT 23.1

Consent of Independent Registered Public Accounting Firm

Emerald Oil, Inc.
Denver, Colorado

We hereby consent to the incorporation by reference in the registration statements on Form S-3 (Nos. 333-196053, 333-172210, 333-181551, 333-184430, 333-187429 and 333-192251) and Form S-8 (Nos. 333-179630, 333-185224 and 333-190230) of Emerald Oil, Inc., of our reports dated March 10, 2015, relating to the consolidated financial statements and the effectiveness of Emerald Oil, Inc.’s internal control over financial reporting which appear in this Form 10-K. 

/S/ BDO USA, LLP

Houston, TX
March 10, 2015

EX-23.2

EXHIBIT 23.2

 

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

We hereby consent to the references to our firm, in the context in which they appear, and to incorporation by reference of our reserves report dated February 18, 2015, included in the Annual Report on Form 10-K of Emerald Oil, Inc. (the "Company") for the fiscal year ended December 31, 2014, as well as in the notes to the financial statements included therein. We also hereby consent to the references to our firm, in the context in which they appear, and to the incorporation by reference of our reserves report dated February 18, 2015, into the Registration Statements on Form S-3 (File Nos. 333-196053, 333-172210, 333-181551, 333-184430, 333-187429, and 333-192251) and Form S-8 (File Nos. 333-179630, 333-185224, and 333-190230) filed with the U.S. Securities and Exchange Commission.

NETHERLAND, SEWELL & ASSOCIATES, INC.
By:	/s/ G. Lance Binder
	G. Lance Binder, P.E.
	Executive Vice President

Dallas, Texas

March 10, 2015

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.

EX-31.1

EXHIBIT 31.1

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

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

1. I have reviewed this annual report on Form 10-K of Emerald Oil, Inc., referred to as the registrant;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

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

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

March 10, 2015	/s/ MCANDREW RUDISILL
	McAndrew Rudisill
	Chief Executive Officer
	(principal executive officer)

EX-31.2

EXHIBIT 31.2

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

I, Ryan Smith, Chief Financial Officer, certify that:

1. I have reviewed this annual report on Form 10-K of Emerald Oil, Inc., referred to as the registrant;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

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

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

March 10, 2015	/s/ RYAN SMITH
	Ryan Smith
	Chief Financial Officer
	(principal financial officer)

EX-32.1

EXHIBIT 32.1

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

In connection with the accompanying annual report of Emerald Oil, Inc., referred to as the Company, on Form 10-K for the year ended December 31, 2014, referred to as the report, I, McAndrew Rudisill, Chief Executive Officer of the Company, hereby certify that, to the best of my knowledge:

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

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

March 10, 2015	/s/ MCANDREW RUDISILL
	McAndrew Rudisill
	Chief Executive Officer
	(principal executive officer)

EX-32.2

EXHIBIT 32.2

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

In connection with the accompanying annual report of Emerald Oil, Inc., referred to as the Company, on Form 10-K for the year ended December 31, 2014, referred to as the report, I, Ryan Smith, Chief Financial Officer of the Company, hereby certify that, to the best of my knowledge:

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

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

March 10, 2015	/s/ RYAN SMITH
	Ryan Smith
	Chief Financial Officer
	(principal financial officer)

EX-99.1

EXHIBIT 99.1

 

February 18, 2015

Mr. McAndrew Rudisill

Emerald Oil, Inc.

1600 Broadway, Suite 1360

Denver, Colorado 80202

Dear Mr. Rudisill:

In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2014, to the Emerald Oil, Inc. (Emerald) interest in certain oil and gas properties located in Montana and North Dakota. We completed our evaluation on or about the date of this letter. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by Emerald. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for Emerald's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

We estimate the net reserves and future net revenue to the Emerald interest in these properties, as of December 31, 2014, to be:

	Net Reserves		Future Net Revenue (M$)
	Oil	Gas		Present Worth
Category	(MBBL)	(MMCF)	Total	at 10%
Proved Developed Producing	12,885.3	11,406.2	737,526.6	407,857.6
Proved Developed Non-Producing	308.8	264.3	17,548.9	10,146.9
Proved Undeveloped	9,632.1	9,399.4	367,257.3	117,082.1
Total Proved	22,826.3	21,069.9	1,122,332.8	535,086.6

Totals may not add because of rounding.

The oil volumes shown include crude oil only. Oil volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

The estimates shown in this report are for proved reserves. No study was made to determine whether probable or possible reserves might be established for these properties. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.

Gross revenue is Emerald's share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for Emerald's share of production taxes, capital costs, abandonment costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.

   

 

Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2014. For oil volumes, the average West Texas Intermediate posted price of $91.48 per barrel is adjusted by lease for quality, transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of $4.350 per MMBTU is adjusted by lease for energy content, transportation fees, and market differentials. Gas prices have been adjusted to include the value for natural gas liquids. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $81.68 per barrel of oil and $7.664 per MCF of gas.

Operating costs used in this report are based on operating expense records of Emerald. These costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Operating costs have been divided into per-well costs and per-unit-of-production costs. Headquarters general and administrative overhead expenses of Emerald are included to the extent that they are covered under joint operating agreements for the operated properties. Operating costs are not escalated for inflation.

Capital costs used in this report were provided by Emerald and are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for workovers, new development wells, and production equipment. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Abandonment costs used in this report are Emerald's estimates of the costs to abandon the wells and production facilities, net of any salvage value. Capital costs and abandonment costs are not escalated for inflation.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.

We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the Emerald interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on Emerald receiving its net revenue interest share of estimated future gross production.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by Emerald, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.

 

For the purposes of this report, we used technical and economic data including, but not limited to, geologic maps, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

The data used in our estimates were obtained from Emerald, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical person primarily responsible for preparing the estimates presented herein meets the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. Joseph J. Spellman, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 1989 and has over 9 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

Sincerely,
NETHERLAND, SEWELL & ASSOCIATES, INC.
Texas Registered Engineering Firm F-2699
By:	/s/ C.H. (Scott) Rees III
	C.H. (Scott) Rees III, P.E.
	Chairman and Chief Executive Officer
By:	/s/ Joseph J. Spellman
	Joseph J. Spellman, P.E. 73709
	Senior Vice President
Date Signed:  February 18, 2015

DMA:TNU

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.

 

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC's Compliance and Disclosure Interpretations.

(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

(ii) Same environment of deposition;

(iii) Similar geological structure; and

(iv) Same drive mechanism.

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Supplemental definitions from the 2007 Petroleum Resources Management System:

Developed Producing Reserves – Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing Reserves – Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.

(ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.

Definitions - Page 1 of 6

 

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.

(iv) Provide improved recovery systems.

(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.

(ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.

(iii) Dry hole contributions and bottom hole contributions.

(iv) Costs of drilling and equipping exploratory wells.

(v) Costs of drilling exploratory-type stratigraphic test wells.

(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

(16) Oil and gas producing activities.

(i) Oil and gas producing activities include:

(A) The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations;

(B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;

(C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:

(1) Lifting the oil and gas to the surface; and

(2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

Definitions - Page 2 of 6

 

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a "terminal point", which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and

b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

(ii) Oil and gas producing activities do not include:

(A) Transporting, refining, or marketing oil and gas;

(B) Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;

(C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or

(D) Production of geothermal steam.

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

Definitions - Page 3 of 6

 

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(20) Production costs.

(i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

(A) Costs of labor to operate the wells and related equipment and facilities.

(B) Repairs and maintenance.

(C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.

(D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

(E) Severance taxes.

(ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

Definitions - Page 4 of 6

 

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

(23) Proved properties. Properties with proved reserves.

(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:

932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year:

a. Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)

b. Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).

The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.

932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:

a. Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.

b. Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.

c. Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves.

d. Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.

Definitions - Page 5 of 6

 

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

e. Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.

f. Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.

(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area.

(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

From the SEC's Compliance and Disclosure Interpretations (October 26, 2009):

Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.

Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:

Ÿ The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);

Ÿ The company's historical record at completing development of comparable long-term projects;

Ÿ The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;

Ÿ The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and

Ÿ The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties. Properties with no proved reserves.

Definitions - Page 6 of 6

XML

ACQUISITION OF BUSINESS (Narrative) (Details) (USD $)	0 Months Ended
	Jul. 26, 2012	Jul. 09, 2012
Business Acquisition [Line Items]
Date company entered into Securities Purchase Agreement with Emerald Oil & Gas NL and Target (Date)		Jul. 09, 2012
Percentage of Emerald common stock equal to amount of stock purchased (in Percent)		19.90%
Number of shares issued to acquire Emerald Oil North America (in Shares)	1,660,000
Debt obligations assumed	$ (20,300,000)
Emerald Oil North America [Member] | Dunn County [Member]
Business Acquisition [Line Items]
Acres acquired in purchase (in Acres)	10,600
Emerald Oil North America [Member] | Sandwash Basin Niobrara [Member]
Business Acquisition [Line Items]
Acres acquired in purchase (in Acres)	45,000

XML

STOCK OPTIONS AND WARRANTS (Schedule of Stock Options Granted, Valuation Assumptions) (Details) (Stock Option [Member])	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk free rates, min (in Percent)	0.58%	0.48%	0.17%
Risk free rates, max (in Percent)	1.42%	2.12%	1.20%
Dividend yield (in Percent)	0.00%	0.00%	0.00%
Expected volatility, min (in Percent)	56.16%	64.64%	69.70%
Expected volatility, max (in Percent)	67.70%	79.50%	78.99%
Weighted average expected life (in Duration)	3 years 6 months	5 years	4 years

XML

PREFERRED AND COMMON STOCK (Summary of Components of Preferred Stock Transactions) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Feb. 19, 2013
Preferred stock value	$ 5,000	$ 5,000
Warrant Liability	2,199,000	15,703,000	8,626,000
Total preferred stock and warrant liability	2,204,000	15,708,000	50,000,000
Series A Preferred Stock [Member]
Preferred stock value			41,369,000
Series B Preferred Stock [Member]
Preferred stock value	$ 5,000	$ 5,000	$ 5,000

XML

FAIR VALUE (Schedule of Fair Value of Warrants Liability Measured on Recurring Basis, Unobservable Inputs) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Balance at beginning of period	$ (15,703,000)
Purchases, issuances, and settlements
Change in Fair Value of Warrant Liability	13,504,000
Transfers
Balance at end of period	$ (2,199,000)

XML

STOCK OPTIONS AND WARRANTS (Schedule of Warrants Granted, Roll Forward) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Number of warrants, outstanding, beginning balance (in Shares)	223,293	223,293	223,293
Number of warrants, granted (in Shares)
Number of warrants, exercised (in Shares)
Number of warrants, outstanding, ending balance (in Shares)	223,293	223,293	223,293	223,293
Warrants outstanding, weighted average exercise price (in Dollars per Share)	$ 6.86	$ 6.86	$ 6.86	$ 6.86
Warrants outstanding, remaining contractual term (in Years) (in Duration)	5 years	6 years	7 years	8 years
Warrants outstanding, intrinsic value		$ 178,634		$ 2,458,251

XML

SUBSEQUENT EVENTS (Narrative) (Details) (USD $)	0 Months Ended							12 Months Ended			0 Months Ended
	Jan. 06, 2015 bbl	Oct. 17, 2013	Oct. 02, 2013	Jun. 04, 2013	May 22, 2013	Sep. 28, 2012	Feb. 08, 2011	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Feb. 19, 2015	Feb. 11, 2015
Number of shares issued under initial public offering									$ 238,354,687	$ 72,167,012
Equity issuance price per share		$ 6.39	$ 6.70	$ 5.87	$ 6.10
Proceeds from the over-allotment exercise			95,500,000			75,000,000	50,000,000		238,354,687	72,167,012
Warrants exercise price							$ 49.70
Monthly Volume (BBLs/m)	120,000
Cash Settlement	5,317,300							(5,542,110)	1,984,778
Minimum [Member]
Warrants exercise price								$ 3.02
Subsequent Event [Member]
Number of shares issued under initial public offering												24,553,571
Equity issuance price per share											$ 1.12	$ 1.12
Proceeds from issuance of stock												26,500,000
Number of stock issued additional											2,605,536
Proceeds from the over-allotment exercise											2,800,000
Monthly Volume (BBLs/m)	120,000
Cash Settlement	$ 5,317,300
Subsequent Event [Member] | Minimum [Member]
Warrants exercise price												$ 3.02
Subsequent Event [Member] | Maximum [Member]
Warrants exercise price												$ 2.05

XML

RELATED PARTY TRANSACTIONS (Narrative) (Details) (USD $)	0 Months Ended			1 Months Ended	0 Months Ended	1 Months Ended		12 Months Ended
	Feb. 19, 2013	Feb. 04, 2013	Jan. 09, 2013	Feb. 28, 2013	May 16, 2014	Oct. 31, 2013	Jun. 30, 2013	Dec. 31, 2014	Dec. 31, 2013
Shares issued during acquisitions		313,700	851,315
Warrants issued to purchase of common stock	5,114,633			5,114,633
Exercise price per share	$ 5.77			$ 5.77				$ 3.02
Value on warrants to purchase of common stock	$ 50,000,000			$ 50,000,000
White Deer Energy [Member]
Shares issued during acquisitions						5,092,852	2,785,600
Resale the shares of common stock					7,878,452
Resale of warrants					5,114,633
Series A Preferred Stock [Member]
Shares issued during acquisitions				500,000
Series A Preferred Stock [Member] | White Deer Energy [Member]
Shares issued during acquisitions	500,000
Series B Preferred Stock [Member]
Shares issued during acquisitions				5,114,633				10,721,824
Exercise price per share									$ 5.77
Series B Preferred Stock [Member] | White Deer Energy [Member]
Shares issued during acquisitions	5,114,633

XML

DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT (Tables)

12 Months Ended

Dec. 31, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Open Commodity Swap Contracts

The following table reflects open commodity swap contracts as of December 31, 2014, the associated volumes and the corresponding weighted average NYMEX reference price:

Settlement Period	Oil (Bbls)		Fixed Price
Oil Swaps
January 1, 2015 – March 31, 2015		30,000	$	93.50
January 1, 2015 – March 31, 2015		36,000		96.05
January 1, 2015 – March 31, 2015		21,000		97.00
January 1, 2015 – March 31, 2015		33,000		97.50
2015 Total/Average		120,000	$	95.98

Schedule of a Reconciliation of the Changes in Fair Value of Commodity Derivatives

The following table sets forth a reconciliation of the changes in fair value of the Company’s commodity derivatives for the years ended December 31, 2014 and 2013.

	2014			2013
Beginning fair value of commodity derivatives	$	(853,005	)	$	(181,248	)
Total gains (losses) on oil derivatives		11,439,240			(2,656,535	)
Cash settlements (received) paid on oil derivatives		(5,542,110	)		1,984,778
Ending fair value of commodity derivatives	$	5,044,125		$	(853,005	)

Schedule of Derivative Instruments in Statement of Financial Position

At December 31, 2014, the Company had derivative financial instruments recorded on the consolidated balance sheet as set forth below:

Type of Contract	Balance Sheet Location
Derivative Assets (Liabilities):
Swap Contracts	Current assets	$	5,044,125
Warrant Liability	Non-current liabilities		(2,199,000	)
Total Derivative Liabilities		$	2,845,125

At December 31, 2013, the Company had derivative financial instruments recorded on the consolidated balance sheet as set forth below:

Type of Contract	Balance Sheet Location
Derivative Assets (Liabilities):
Swap Contracts	Current liabilities	$	(921,401	)
Swap Contracts	Non-current assets		68,396
Warrant Liability	Non-current liabilities		(15,703,000	)
Total Derivative Liabilities		$	(16,556,005	)

XML

SUBSEQUENT EVENTS (Summary of Oil Derivative Swap) (Details) (USD $)	0 Months Ended	12 Months Ended
	Jan. 06, 2015 bbl	Dec. 31, 2014	Dec. 31, 2013
Monthly Volume (BBLs/m)	120,000
Settlement Price	95.98
Cover Price	51.67
Cash Settlement	$ 5,317,300	$ (5,542,110)	$ 1,984,778
Subsequent Event [Member]
Monthly Volume (BBLs/m)	120,000
Cash Settlement	5,317,300
Subsequent Event [Member] | January 1, 2015 - March 31, 2015 [Member]
Monthly Volume (BBLs/m)	30,000
Settlement Price	93.50
Cover Price	51.67
Cash Settlement	1,255,000
Subsequent Event [Member] | January 1, 2015 - March 31, 2015 [Member]
Monthly Volume (BBLs/m)	36,000
Settlement Price	96.05
Cover Price	51.67
Cash Settlement	1,597,800
Subsequent Event [Member] | January 1, 2015 - March 31, 2015 [Member]
Monthly Volume (BBLs/m)	21,000
Settlement Price	97.00
Cover Price	51.67
Cash Settlement	952,000
Subsequent Event [Member] | January 1, 2015 - March 31, 2015 [Member]
Monthly Volume (BBLs/m)	33,000
Settlement Price	97.50
Cover Price	51.67
Cash Settlement	$ 1,512,500

XML

DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT (Schedule of Commodity Derivatives, Changes in Fair Value, Reconciliation) (Details) (USD $)	0 Months Ended	12 Months Ended
	Jan. 06, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Beginning fair value of commodity derivatives		$ (853,005)	$ (181,248)
Total gains (losses) on oil derivatives		11,439,240	(2,656,535)	(215,439)
Cash settlements (received) paid on oil derivatives	5,317,300	(5,542,110)	1,984,778
Ending fair value of commodity derivatives		$ 5,044,125	$ (853,005)	$ (181,248)

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STOCK OPTIONS AND WARRANTS (Schedule of Warrants Granted, Valuation Assumptions) (Details) (Warrants [Member])	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013		Dec. 31, 2012
Warrants [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk free rates (in Percent)			[1]
Dividend yield (in Percent)			[1]
Expected volatility (in Percent)			[1]
Weighted average expected life (in Duration)	0 years	0 years	[1]	0 years

[1] See Note 14 - Derivative Instruments and Price Risk Management - Warrant Liability for the method and assumptions used to value the warrants issued on February 19, 2013 associated with the preferred stock transaction.

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COMMITMENTS AND CONTINGENCIES (Minimum Rental Commitments Under All Non-Cancelable Operating Leases) (Details) (USD $)	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Payment Due in the Year Ended December 31, 2015	$ 464,088
Payment Due in the Year Ended December 31, 2016	472,630
Payment Due in the Year Ended December 31, 2017	481,171
Payment Due in the Year Ended December 31, 2018	489,713
Payment Due in the Year Ended December 31, 2019	412,839
Operating Leases, Future Minimum Payments Due	$ 2,320,441

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COMMITMENTS AND CONTINGENCIES (Minimum Rental Commitments Under All Non-Cancelable Operating Leases) (Details) (Parenthetical)	0 Months Ended
	Dec. 15, 2012
Commitments and Contingencies Disclosure [Abstract]
Lease expiration year month	2019-10
Lease term (in Duration)	66 months

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DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT (Narrative) (Details) (USD $)	0 Months Ended	12 Months Ended
	Jan. 06, 2015 bbl	Dec. 31, 2014	Dec. 31, 2013	Feb. 08, 2011
Total number of barrels of oil (in Integer)	120,000
Cash settlement received	$ 5,317,300	$ (5,542,110)	$ 1,984,778
Fair value of warrant		2,199,000	15,703,000
Warrants issued, price per warrant (in Dollars per Unit)				$ 49.70
Warrant [Member]
Fair value of warrant		2,199,000
Warrants issued, price per warrant (in Dollars per Unit)		$ 0.43
Fair value assumption of expected term (in Duration)		1255 days
Fair value assumption of exercise price (in Dollars per Unit)		$ 3.02
Fair value assumption of stock price (in Dollars per Unit)		$ 1.20
Fair value assumption of expected volatility rate (in Percent)		61.00%
Fair value assumption of risk-free interest rate (in Percent)		1.65%
Warrant [Member] | Securities Purchase Agreement [Member]
Fair value of warrant		8,626,000
Warrants issued, price per warrant (in Dollars per Unit)		$ 1.69
Fair value assumption of expected term (in Duration)		1798 days
Fair value assumption of exercise price (in Dollars per Unit)		$ 5.77
Fair value assumption of expected volatility rate (in Percent)		40.00%
Fair value assumption of risk-free interest rate (in Percent)		1.38%
January 5, 2015 [Member] | NYMEX West Texas Intermediate [Member] | Swap [Member]
Total number of barrels of oil (in Integer)		120,000
Cash settlement received		$ 5,317,300

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ACQUISITION OF BUSINESS (Tables)

12 Months Ended

Dec. 31, 2014

Business Combinations [Abstract]

Schedule of Busines Acquisition, Emerald Oil North America

The Company recorded a gain on the bargain purchase of Emerald Oil North America as a result of the decrease in the Company’s share price between the announcement date (July 10, 2012) and closing date (July 26, 2012) of the acquisition in accordance with GAAP. A summary of the acquisition is below (in thousands):

Proved Oil and Natural Gas Properties	$	6,839
Unproved Oil and Natural Gas Properties		33,948
Other Assets		111
Debt Assumed		(20,303	)
Net Assets Acquired		20,595
Equity Issued to Emerald Oil NL		(13,381	)
Gain on Acquisition		7,214
Less: Acquisition Costs		(1,456	)
Gain on Acquisition, net	$	5,758

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STOCK OPTIONS AND WARRANTS (Narrative) (Details) (USD $)	0 Months Ended											12 Months Ended
	Sep. 30, 2014	Sep. 22, 2014	Jun. 30, 2014	Mar. 31, 2014	Jan. 10, 2014	Oct. 17, 2013	Oct. 02, 2013	Jun. 04, 2013	May 22, 2013	Sep. 28, 2012	Feb. 08, 2011	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock options granted to employees	3,400	19,000	7,700	255,499	295,800
Stock options granted to purchase common stock exercisable price per share	$ 6.15	$ 6.80	$ 7.65	$ 6.69	$ 7.48							$ 10.03	$ 11.12	$ 11.39
Stock options award vesting period	36 months	36 months	36 months	36 months	36 months
Stock options award vesting	1,133	6,333	2,566	85,166	98,600
Stock options award vesting dates	September 30, 2015, 2016 and 2017	September 22, 2015, 2016 and 2017	July 1, 2015, 2016 and 2017	April 1, 2015, 2016 and 2017	January 10, 2015, 2016 and 2017
Stock-based compensation expense												$ 894,303	$ 1,600,924	$ 2,634,681
Share based compensation, tax												0	0	0
Total unrecognized compensation cost related to nonvested stock options granted												923,614
Remaining cost expected to be recognized, weighted-average period												10 months 28 days
Common stock sold (in Shares)						5,092,852	15,000,000	2,785,600	12,000,000	13,392,857	1,785,714
Warrants exercise price											$ 49.70
Warrants [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense												0	0	0
Common stock sold (in Shares)											1,785,714
Warrants issued in conjunction with sale of common stock (in Shares)											892,858
Warrants exercise price											$ 49.70
Warrants expired or forfeited (in Shares)												0
Oil and Gas Properties [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share based compensation, capitalized												$ 631,992	$ 1,193,960	$ 249,367

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OIL AND NATURAL GAS PROPERTIES (Summary of Purchase Price of Acquisition Assets Acquired and Liabilities Assumed) (Details) (USD $)	Sep. 30, 2014
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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COMMITMENTS AND CONTINGENCIES (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Commitments and Contingencies Disclosure [Abstract]
Rent expenses for leased facilities and other equipment rentals	$ 362,873	$ 399,382	$ 115,659

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ORGANIZATION AND NATURE OF BUSINESS (Narrative) (Details)	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Entity, number of employees (in Employees)	42

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STOCK OPTIONS AND WARRANTS (Schedule of Nonvested Stock Options, Roll Forward) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Number of Options Nonvested, beginning balance (in Shares)	694,587	410,716
Nonvested stock options, granted (in Shares)	581,399	505,301	685,713
Nonvested stock options, vested (in Shares)	(373,024)	(200,000)
Nonvested stock options, forfeited (in Shares)	(270,956)	(21,430)
Number of Options Nonvested, ending balance (in Shares)	632,006	694,587	410,716
Nonvested options, weighted-average grant-date fair value, beginning balance (in Dollars per Share)	$ 7.41	$ 5.87
Nonvested options, weighted-average grant-date fair value, granted (in Dollars per Share)	$ 7.48	$ 7.18
Nonvested options, weighted-average grant-date fair value, vested (in Dollars per Share)	$ 7.43	$ 10.47
Nonvested options, weighted-average grant-date fair value, forfeited (in Dollars per Share)	$ 7.12	$ 12.39
Nonvested options, weighted-average grant-date fair value, ending balance (in Dollars per Share)	$ 6.91	$ 7.41	$ 5.87

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INCOME TAXES (Schedule of the Components of the Deferred Tax Asset) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Deferred Tax Assets:
Net Operating Loss Carryforwards (NOLs)	$ 41,697,116	$ 36,382,177
Stock-based Compensation	5,023,270	3,245,308
Accrued Liability	1,595,333
Derivatives		323,190
Equity Investments		116,886
Oil and Natural Gas Properties	194,329
Total Deferred Tax Assets	48,510,048	40,067,561
Deferred Tax Liabilities:
Oil and Natural Gas Properties		11,093,181
Derivatives	1,877,126
Other	55,711	7,353
Total Deferred Tax Liabilities	1,932,837	11,100,534
Less: Valuation Allowance	(46,577,211)	(28,967,027)
Total Net Deferred Tax Asset

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ASSET RETIREMENT OBLIGATION (Narrative) (Details)	12 Months Ended
	Dec. 31, 2012
Asset Retirement Obligation Disclosure [Abstract]
Significant input to assumption, asset retirement obligation valuation, future inflation factor (in Percent)	2.50%
Significant input to assumption, asset retirement obligation valuation, interest rate credit-adjusted risk-free (in Percent)	7.00%

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PREFERRED AND COMMON STOCK (Narrative) (Details) (USD $)	0 Months Ended										1 Months Ended	12 Months Ended			0 Months Ended	1 Months Ended
	Sep. 10, 2014	Oct. 17, 2013	Oct. 02, 2013	Jun. 04, 2013	May 22, 2013	Feb. 19, 2013	Feb. 04, 2013	Jan. 09, 2013	Sep. 28, 2012	Feb. 08, 2011	Feb. 28, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Feb. 28, 2012	Oct. 31, 2013	Jun. 30, 2013
Shares issued during acquisitions							313,700	851,315
Warrants issued to purchase of common stock						5,114,633					5,114,633
Exercise price per share						$ 5.77					$ 5.77	$ 3.02
Value on warrants to purchase of common stock						$ 50,000,000					$ 50,000,000
Warrants exercisable period						Dec. 31, 2019
Principal amount on outstanding shares													50,000,000
Redemption premiums													6,250,000
Preferred stock, shares outstanding													5,114,633
Dividends paid													2,582,191
Warrants exercise price										$ 49.70
Issuance of shares		5,092,852	15,000,000	2,785,600	12,000,000				13,392,857	1,785,714
Subscription price per share			$ 6.70						$ 5.60	$ 28.00
Gross proceeds from issuance of common stock			95,500,000						75,000,000	50,000,000			238,354,687	72,167,012
Shares issuable upon exercise of warrants										892,857
Common stock offering costs			5,000,000		4,300,000				5,300,000	3,397,749
Additional shares issued			2,250,000
Net proceeds of common stock		32,500,000	14,400,000	16,200,000	69,300,000				2,500,000
Issuance of shares, per share		$ 6.39	$ 6.70	$ 5.87	$ 6.10
Placement agent fees				200,000
Debt conversion expense												10,438,080
Compensation expense associated with restricted stock units granted	213,228											10,457,009	10,903,696	4,684,009
Oil and Natural Gas Properties [Member]
Capitalized compensation expense												1,641,664	851,979	332,673
Non Vested Restricted Stock Units [Member]
Compensation expense associated with restricted stock units granted												2,124,950
Issuance of restricted shares												584,620
Weighted average restricted stock in period												8 months 12 days
Vesting of Stock Unit Grants [Member]
Compensation expense associated with restricted stock units granted												919,633
Common Stock [Member]
Shares issued during acquisitions														1,662,174
Issuance of shares													38,928,452	13,877,555
Gross proceeds from issuance of common stock															2,700,000
Additional shares issued									484,698
Issuance of shares, per share															$ 5.60
Issuance of restricted shares												1,266,419		74,285
Common Stock One [Member]
Additional shares issued					1,800,000
Net proceeds of common stock					10,500,000
Issuance of shares, per share					$ 6.10
Minimum [Member]
Warrants exercise price												$ 3.02
Percentage on rate of return												25.00%
Series A Preferred Stock [Member]
Shares issued during acquisitions											500,000
Fair value of preferred stock												38,552,994
Preferred stock offering costs												2,816,006
Series B Preferred Stock [Member]
Shares issued during acquisitions											5,114,633	10,721,824
Exercise price per share													$ 5.77
Preferred stock liquidation preference per share												$ 0.001
Preferred shares redemption price per share												$ 0.001
Convertible notes													21,000,000
Fair value of preferred stock												5,000
Fair value of warrant liability												$ 8,626,000
White Deer Energy [Member]
Shares issued during acquisitions																5,092,852	2,785,600
White Deer Energy [Member] | Series A Preferred Stock [Member]
Shares issued during acquisitions						500,000
White Deer Energy [Member] | Series B Preferred Stock [Member]
Shares issued during acquisitions						5,114,633

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OIL AND NATURAL GAS PROPERTIES

12 Months Ended

Dec. 31, 2014

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

OIL AND NATURAL GAS PROPERTIES

NOTE 4  OIL AND NATURAL GAS PROPERTIES

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

Acquisitions

On February 13, 2014, the Company acquired approximately 19,500 net acres located in Williams and McKenzie Counties, North Dakota from an unrelated third party for approximately $69.2 million in cash. Net daily production from the acreage was approximately 300 Boe/d as of January 1, 2014, the effective date of the transaction. The acquisition was accounted for as an asset purchase. Related transaction costs were capitalized to oil and natural gas properties.

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

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

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

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

Pro Forma Operating Results

In accordance with ASC Topic 805, presented below are unaudited pro forma results for the year ended December 31, 2014 and 2013 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:

	Year Ended December 31,
	2014			2013
Revenues	$	126,418,589		$	57,151,128
Net Loss Available to Common Stockholders	$	(48,179,709	)	$	(29,179,483	)
Net Loss Per Share – Basic and Diluted	$	(0.72	)	$	(0.71	)
Weighted Average Shares Outstanding – Basic and Diluted		66,772,458			41,383,277

Post-Acquisition Operating Results

The amount of revenues and excess of revenues over direct operating expenses included in the accompanying Consolidated Statements of Operations for the September 2014 acquisition is shown in the table that follows. Direct operating expenses include lease operating expenses, selling, general and administrative expenses and production and other taxes.

	Year Ended December 31,
	2014		2013
Revenues	$	2,590,658	$	—
Excess of revenues over direct operating expenses	$	1,299,829	$	—

Leasehold Sales

On March 28, 2013, the Company sold its undivided 45% working interest in and to certain oil and natural gas leaseholds in the Sand Wash Basin, comprising approximately 31,000 net acres located in Routt and Moffatt Counties, Colorado and Carbon County, Wyoming for an aggregate sale price of approximately $10.1 million in cash. No gain or loss was recognized as the sale did not significantly alter the relationship between capitalized costs and proved reserves. In December 2013, the Company sold its remaining oil and natural gas assets in the Sand Wash Basin, primarily comprised of 14,600 net acres in Routt County, Colorado to an unrelated third party for approximately $2.0 million.

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

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

On September 6, 2013, the Company sold its interest in 26,579 non-operated net acres located in the Williston Basin and the associated oil and natural gas production to an unrelated third party for a total sales price of approximately $111.0 million in cash, including sales price adjustments for development costs and production revenue and operating expenses during the effective period and subject to certain post-closing adjustments. $11.0 million of the sales price will remain in escrow upon finalization of standard due diligence procedures. On February 21, 2014, $8.6 million was released to Emerald, with the remaining $2.4 million returned to the buyer for purchase price adjustments during the due diligence period. The acreage was associated with non-operated working interests in Williston Basin Bakken and Three Forks wells. Under the full cost method of accounting for oil and natural gas operations, sales of oil and natural gas properties, whether or not being amortized, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to the cost center. The sale represented greater than 25 percent of the Company’s proved reserves of oil and natural gas attributable to the full cost pool. As a result, there was a significant alteration in the relationship between capitalized costs and proved reserves of oil and gas attributable to the full cost pool. Total capitalized costs within the full cost pool are allocated on the basis of the relative fair values of the properties sold and those retained due to substantial economic differences between the properties sold and those retained. Following this methodology, the following table represents a net sales price allocation of the transaction (in thousands):

Sale price	$	111,090
Add:  Disposition of asset retirement obligations		309
Less: Sale expenses		(1,168	)
Purchase price adjustments		(1,520	)
Sale price, net	$	108,711
Proved oil and natural gas properties	$	137,279
Accumulated depletion		(49,508	)
Unproved oil and natural gas properties		13,568
Gain on sale		7,372
Sale price, net	$	108,711

On September 2, 2014 the Company assigned approximately 4,300 net acres located in Williams County, North Dakota to an unrelated third party as partial consideration for an acquisition transaction. The fair value allocated to the acreage was approximately $35,918,000, including sales price adjustments for development costs and production revenue and operating expenses during the effective period. The acreage was associated with operated working interests in Williston Basin Bakken and Three Forks wells. No gain or loss was recognized as the sale did not significantly alter the relationship between capitalized costs and proved reserves.

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ASSET RETIREMENT OBLIGATION (Schedule of Change in Asset Retirement Obligation) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Asset Retirement Obligation Disclosure [Abstract]
Beginning Asset Retirement Obligation	$ 692,137	$ 296,074	$ 116,119
Revision of Previous Estimates	148,968	165,968
Liabilities Incurred or Acquired	1,817,939	510,271	164,967
Accretion of Discount on Asset Retirement Obligations	104,803	32,449	14,988
Wells Settled through P&A	(72,555)
Liabilities Associated with Properties Sold	(19,317)	(312,625)
Ending Asset Retirement Obligation	$ 2,671,975	$ 692,137	$ 296,074

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OIL AND NATURAL GAS PROPERTIES (Proforma Information of Future Results Operations) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Revenues	$ 126,418,589	$ 57,151,128
Net Loss Available to Common Stockholders	$ (48,179,709)	$ (29,179,483)
Net Loss Per Share - Basic and Diluted	$ (0.72)	$ (0.71)
Weighted Average Shares Outstanding - Basic and Diluted	66,772,458	41,383,277	12,699,544

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ASSET RETIREMENT OBLIGATION (Tables)

12 Months Ended

Dec. 31, 2014

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Change in Asset Retirement Obligation

The following table summarizes the Company’s asset retirement obligation transactions for the years ended December 31, 2014, 2013 and 2012:

	2014			2013			2012
Beginning Asset Retirement Obligation	$	692,137		$	296,074		$	116,119
Revision of Previous Estimates		148,968			165,968			—
Liabilities Incurred or Acquired		1,817,939			510,271			164,967
Accretion of Discount on Asset Retirement Obligations		104,803			32,449			14,988
Wells Settled through P&A		(72,555	)		—			—
Liabilities Associated with Properties Sold		(19,317	)		(312,625	)		—
Ending Asset Retirement Obligation	$	2,671,975		$	692,137		$	296,074

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STOCK OPTIONS AND WARRANTS (Tables)

12 Months Ended

Dec. 31, 2014

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Schedule of Stock Options, Roll Forward

A summary of options for the years ended December 31, 2014, 2013, and 2012 is as follows:

	Number of Options			Weighted Average Exercise Price		Remaining Contractual Term (in Years)		Intrinsic Value
Outstanding at January 1, 2012		150,000		$	20.44		7.2		—
Granted		685,713			8.11		—		—
Exercised		—			—		—		—
Forfeited or Expired		—			—		—		—
Outstanding at December 31, 2012		835,713			10.43		7.7		—
Granted		505,301			7.18		—		—
Exercised		(75,000	)		4.43		—		—
Forfeited or Expired		(107,143	)		16.54		—		—
Outstanding at December 31, 2013		1,158,871			8.90		4.8		—
Granted		581,399			7.11		—		—
Exercised		(75,000	)		4.43		—		—
Forfeited or Expired		(470,591	)		8.26		—		—
Outstanding at December 31, 2014		1,194,679		$	8.56		3.7	$	—
Stock Options Exercisable at December 31, 2012		424,997		$	11.39		5.9	$	121,500
Stock Options Exercisable at December 31, 2013		464,273		$	11.12		3.1	$	356,024
Stock Options Exercisable at December 31, 2014		562,673		$	10.03		2.8	$	—

Schedule of Nonvested Options

A summary of the status of the Company’s nonvested options as of December 31, 2014 and changes during the year then ended is as follows:

	Number of Options			Weighted-Average Grant-Date Fair Value
Nonvested at December 31, 2012		410,716		$	5.87
Granted		505,301			7.18
Vested		(200,000	)		10.47
Forfeited		(21,430			12.39
Nonvested at December 31, 2013		694,587			7.41
Granted		581,399			7.48
Vested		(373,024	)		7.43
Forfeited		(270,956	)		7.12
Nonvested at December 31, 2014		632,006		$	6.91

Schedule of Stock Options, Additional Information

For the year ended December 31, 2014, 2013 and 2012, other information pertaining to stock options was as follows:

	2014		2013		2012
Weighted-average per share grant-date fair value of stock options granted	$	7.11	$	4.43	$	4.62
Total intrinsic value of options exercised		257,250		211,250		—
Total grant-date fair value of stock options vested during the year		1,557,619		2,093,999		2,159,307

Schedule of Stock Options Granted, Valuation Assumptions

The following assumptions were used for the Black-Scholes model to value the options granted during the years ended December 31, 2014, 2013 and 2012.

	2014	2013	2012
Risk free rates	0.58% to 1.42%	0.48% to 2.12%	0.17% to 1.20%
Dividend Yield	0%	0%	0%
Expected volatility	56.16% to 67.70%	64.64% to 79.50%	69.70% to 78.99%
Weighted average expected life	3.5 years	5 years	4 years

Schedule of Warrants, Roll Forward

A summary of warrants granted to employees, directors and consultants for the years ended December 31, 2014, 2013 and 2012 is as follows:

	Number of Warrants		Weighted Average Exercise Price		Remaining Contractual Term (in Years)		Intrinsic Value
Outstanding at December 31, 2011		223,293	$	6.86		8.0	$	2,458,251
Granted		—		—		—		—
Exercised		—		—		—		—
Outstanding at December 31, 2012		223,293		6.86		7.0		—
Granted		—		—		—		—
Exercised		—		—		—		—
Outstanding at December 31, 2013		223,293		6.86		6.0		178,634
Granted		—		—		—		—
Exercised		—		—		—		—
Outstanding at December 31, 2014		223,293	$	6.86		5.0	$	—

Schedule of Warrants, Additional Information

For the years ended December 31, 2014, 2013 and 2012, other information pertaining to warrants was as follows:

	2014		2013 (1)		2012
Weighted-average grant-date fair value of warrants granted	$	—	$	1.69	$	—
Total intrinsic value of warrants exercised	$	—	$	—	$	—
Total grant-date fair value of warrants vested during the year	$	—	$	—	$	—

Schedule of Warrants, Valuation Assumptions

The following assumptions were used for the Black-Scholes model to value the warrants granted during the years ended December 31, 2014, 2013 and 2012.

	2014		2013 (1)		2012
Risk free rates		—		—		—
Dividend yield		—		—		—
Expected volatility		—		—		—
Weighted average expected life		—		—		—

Schedule of Status of Warrants Outstanding

The table below reflects the status of warrants outstanding at December 31, 2014:

	Warrants		Exercise Price		Expiration Date
December 1, 2009		37,216	$	6.86	December 1, 2019
December 31, 2009		186,077	$	6.86	December 31, 2019
February 8, 2011		892,858	$	49.70	February 8, 2016
February 19, 2013 (1)		5,114,633	$	3.02	December 31, 2019
Total		6,230,784

(1) See Note 16 – Subsequent Events for details on the warrant price adjustment subsequent to December 31, 2014.

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STOCK OPTIONS AND WARRANTS (Schedule of Warrants, Additional Information) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013		Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted-average grant-date fair value of warrants granted	$ 7.48	$ 7.10		$ 4.93
Warrants [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted-average grant-date fair value of warrants granted		$ 1.69	[1]
Total intrinsic value of warrants exercised			[1]
Total grant-date fair value of warrants vested during the year			[1]

[1] See Note 6 - Common and Preferred Stock - Preferred Stock for details on the warrants issued on February 19, 2013 associated with the preferred stock transaction.

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OIL AND NATURAL GAS PROPERTIES (Summary of Post Acquisition Operating Results) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Revenues	$ 2,590,658
Excess of revenues over direct operating expenses	$ 1,299,829

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ACCRUED LIABILITIES (Tables)

12 Months Ended

Dec. 31, 2014

Payables and Accruals [Abstract]

Schedule of Accrued Liabilities

NOTE 11 ACCRUED LIABILITIES

The Company’s accrued liabilities consist of the following:

	December 31,
	2014		2013
Accrued Transaction Adjustments	$	249,764	$	2,067,150
Oil and Natural Gas Revenue Payable		4,667,935		7,451,394
Other General and Administrative Expenses		6,350,132		2,303,185
Total Accrued Liabilities	$	11,267,831	$	11,821,729

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INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2014

Income Tax Disclosure [Abstract]

Schedule of Income Tax Expense (Benefit)

The income tax expense (benefit) for the year ended December 31, 2014, 2013, and 2012 consists of the following:

	2014		2013		2012
Current Income Taxes	$	—	$	—	$	—
Deferred Income Taxes
Federal		—		—		—
State		—		—		—
Total Benefit	$	—	$	—	$	—

Schedule of Income Tax Expense Reconciliation

Reconciliation of reported amount of income tax expense:

	2014			2013			2012
Loss Before Taxes	$	(52,145,225	)	$	(10,882,895	)	$	(62,296,099	)
Federal Statutory Rate		35	%		35	%		35	%
Benefit Computed at Federal Statutory Rates		(18,250,829	)		(3,809,013	)		(21,803,635	)
State Benefit, Net of Federal Benefit		(923,445	)		(102,503	)		(1,969,364	)
Effects of:
Warrant Revaluation		(4,726,400	)		2,476,950			—
Debt Conversion Expense		3,653,328			—			—
Cancellation of Debt Income		2,646,473			—			—
Nondeductible Expenses		21,155			366,203			10,941
Other		(30,466	)		125,956			(119,872	)
Change in Valuation Allowance		17,610,184			942,407			23,881,930
Reported Benefit	$	—		$	—		$	—

Schedule of Deferred Tax Assets

The components of the Company’s deferred tax asset were as follows:

	Year Ended December 31,
	2014			2013
Deferred Tax Assets:
Net Operating Loss Carryforwards (NOLs)	$	41,697,116		$	36,382,177
Stock-based Compensation		5,023,270			3,245,308
Accrued Liability		1,595,333			—
Derivatives		—			323,190
Equity Investments		—			116,886
Oil and Natural Gas Properties		194,329			—
Total Deferred Tax Assets		48,510,048			40,067,561
Deferred Tax Liabilities:		—
Oil and Natural Gas Properties		—			11,093,181
Derivatives		1,877,126			—
Other		55,711			7,353
Total Deferred Tax Liabilities		1,932,837			11,100,534
Less: Valuation Allowance		(46,577,211	)		(28,967,027	)
Total Net Deferred Tax Asset	$	—		$	—

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ACQUISITION OF BUSINESS

12 Months Ended

Dec. 31, 2014

Business Combinations [Abstract]

ACQUISITION OF BUSINESS

NOTE 3  ACQUISITION OF BUSINESS

On July 9, 2012, the Company entered into a Securities Purchase Agreement (the “Purchase Agreement”) with Emerald Oil & Gas NL (the “Parent”) and Emerald Oil North America, Inc., a wholly owned subsidiary of the Parent, pursuant to which the Company purchased all of the outstanding capital stock of Emerald Oil North America for approximately 19.9% of the total shares of the Company’s common stock outstanding as of the closing date. The Company completed the acquisition of Emerald Oil North America on July 26, 2012 and issued approximately 1.66 million shares to the Parent. The Company assumed Emerald Oil North America’s liabilities, including approximately $20.3 million in debt owed by Emerald Oil North America. The acquisition included approximately 10,600 net acres located in Dunn County, North Dakota and approximately 45,000 net acres in the Sand Wash Basin Niobrara shale oil play in northwestern Colorado and southwestern Wyoming.

The Emerald Oil North America acquisition was accounted for using the acquisition method. Assets acquired and liabilities assumed were recorded at their estimated fair values as of the acquisition date. The allocation of the purchase price is based upon a valuation of certain assets acquired and liabilities assumed. The Company recorded a gain on the bargain purchase of Emerald Oil North America as a result of the decrease in the Company’s share price between the announcement date (July 10, 2012) and closing date (July 26, 2012) of the acquisition in accordance with GAAP. A summary of the acquisition is below (in thousands):

Proved Oil and Natural Gas Properties	$	6,839
Unproved Oil and Natural Gas Properties		33,948
Other Assets		111
Debt Assumed		(20,303	)
Net Assets Acquired		20,595
Equity Issued to Emerald Oil NL		(13,381	)
Gain on Acquisition		7,214
Less: Acquisition Costs		(1,456	)
Gain on Acquisition, net	$	5,758

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FAIR VALUE (Tables)

12 Months Ended

Dec. 31, 2014

Fair Value Disclosures [Abstract]

Schedule of Fair Value of Financial Instruments Measured on Recurring Basis

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

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

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

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

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

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

Balance, at December 31, 2013	$	(15,703,000	)
Purchases, issuances, and settlements		—
Change in Fair Value of Warrant Liability		13,504,000
Transfers		—
Balance, at December 31, 2014	$	(2,199,000	)

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ACQUISITION OF BUSINESS (Schedule of Business Acquisition) (Details) (USD $)	12 Months Ended			0 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jul. 26, 2012	Sep. 30, 2014
Business Acquisition [Line Items]
Net Assets Acquired					$ 1,121
Gain on Acquisition			7,213,835
Less: Acquisition Costs	409,712
Emerald Oil North America [Member]
Business Acquisition [Line Items]
Proved Oil and Natural Gas Properties				6,839,000
Unproved Oil and Natural Gas Properties				33,948,000
Other Assets				111,000
Debt Assumed				20,303,000
Net Assets Acquired				20,595,000
Equity Issued to Emerald Oil & Gas NL				13,381,000
Gain on Acquisition				7,213,835
Less: Acquisition Costs				(1,456,000)
Gain on Acquisition, net				$ 5,758,048

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STOCK OPTIONS AND WARRANTS (Schedule of Stock Options, Additional Information) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Weighted-average per share grant-date fair value of stock options granted (in Dollars per Share)	$ 7.11	$ 4.43	$ 4.62
Total intrinsic value of options exercised	$ 257,250	$ 211,250
Total grant-date fair value of stock options vested during the year	$ 1,557,619	$ 2,093,999	$ 2,159,307

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DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT (Volumes and Corresponding Weighted Average NYMEX Reference Price) (Details)	0 Months Ended	12 Months Ended
	Jan. 06, 2015 bbl	Dec. 31, 2014 bbl
Oil (Bbls)	120,000
January 1, 2015 - March 31, 2015 [Member]
Oil (Bbls)		30,000
Fixed Price		93.50
January 1, 2015 - March 31, 2015 [Member]
Oil (Bbls)		36,000
Fixed Price		96.05
January 1, 2015 - March 31, 2015 [Member]
Oil (Bbls)		21,000
Fixed Price		97.00
January 1, 2015 - March 31, 2015 [Member]
Oil (Bbls)		33,000
Fixed Price		97.50
2015 Total/Average [Member]
Oil (Bbls)		120,000
Fixed Price		95.98

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CONSOLIDATED BALANCE SHEETS (USD $)	Dec. 31, 2014	Dec. 31, 2013
CURRENT ASSETS
Cash and Cash Equivalents	$ 12,389,230	$ 144,255,438
Restricted Cash		15,000,512
Accounts Receivable - Oil and Natural Gas Sales	7,203,455	8,715,821
Accounts Receivable - Joint Interest Partners	31,842,464	31,523,204
Other Receivables	980,317	577,409
Prepaid Expenses and Other Current Assets	289,061	206,299
Fair Value of Commodity Derivatives	5,044,125
Total Current Assets	57,748,652	200,278,683
Oil and Natural Gas Properties, Full Cost Method, at cost:
Proved Oil and Natural Gas Properties	593,472,170	211,015,067
Unproved Oil and Natural Gas Properties	166,708,263	57,015,315
Equipment and Facilities	6,086,896	1,837,744
Other Property and Equipment	2,583,372	890,811
Total Property and Equipment	768,850,701	270,758,937
Less - Accumulated Depreciation, Depletion and Amortization	(149,703,417)	(48,176,522)
Total Property and Equipment, Net	619,147,284	222,582,415
Restricted Cash	4,000,000	6,000,000
Fair Value of Commodity Derivatives		68,396
Debt Issuance Costs, Net of Amortization	5,779,125	475,157
Deposits on Acquisitions	140,173	125,368
Deferred Tax Asset, Net	1,813,796
Other Non-Current Assets	430,846	357,644
Total Assets	689,059,876	429,887,663
CURRENT LIABILITIES
Accounts Payable	120,136,903	63,168,422
Fair Value of Commodity Derivatives		921,401
Accrued Expenses	11,267,831	11,821,729
Advances from Joint Interest Partners	2,577,247	2,205,538
Deferred Tax Liability, Net	1,813,796
Total Current Liabilities	135,795,777	78,117,090
LONG-TERM LIABILITIES
Revolving Credit Facility	75,000,000
Convertible Senior Notes	151,500,000
Asset Retirement Obligations	2,671,975	692,137
Warrant Liability	2,199,000	15,703,000
Other Non-Current Liabilities		56,327
Total Liabilities	367,166,752	94,568,554
COMMITMENTS AND CONTINGENCIES
Preferred Stock - Par Value $.001; 20,000,000 Shares Authorized;
Series B Voting Preferred Stock - 5,114,633 issued and outstanding at December 31, 2014 and December 31, 2013. Liquidation preference value of $5,115 as of December 31, 2014 and December 31, 2013.	5,000	5,000
STOCKHOLDERS' EQUITY
Common Stock, Par Value $.001; 500,000,000 Shares Authorized, 77,828,613 and 65,840,370 Shares Issued and Outstanding, respectively	77,828	65,840
Additional Paid-In Capital	455,008,596	416,301,344
Accumulated Deficit	(133,198,300)	(81,053,075)
Total Stockholders' Equity	321,888,124	335,314,109
Total Liabilities and Stockholders' Equity	$ 689,059,876	$ 429,887,663

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OIL AND NATURAL GAS PROPERTIES (Summary of Net Sales Price Allocation) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Sale price	$ 111,090
Add: Disposition of asset retirement obligations	309
Less: Sale expenses	(1,168)
Purchase price adjustments	(1,520)
Sale price, net	108,711
Proved oil and natural gas properties	137,279
Accumulated depletion	(49,508)
Unproved oil and natural gas properties	13,568
Gain on sale	$ 7,372

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CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (DEFICIT) (USD $)	Common Stock [Member]	Additional Paid-in Capital [Member]	Accumulated Deficit [Member]	Total
Balance, beginning of period at Dec. 31, 2011	$ 8,264	$ 87,007,758	$ (7,847,081)	$ 79,141,941
Balance, beginning of period (in Shares) at Dec. 31, 2011	8,264,062
Common Shares Issued as Compensation	910	3,837,212		3,838,122
Common Shares Issued as Compensation (in Shares)	910,296
Restricted Stock Grants	74	(74)
Restricted Stock Grants (in Shares)	74,285
Net Proceeds from Equity Offering	13,878	72,153,134		72,167,012
Net Proceeds from Equity Offering (in Shares)	13,877,555
Restricted Stock Grant Compensation		1,178,559		1,178,559
Director Fees Related to Stock Option Grants		1,104,147		1,104,147
Restricted Stock Forfeited	(53)	53
Restricted Stock Forfeited (in Shares)	(53,572)
Compensation Related to Stock Option Grants		1,779,901		1,779,901
Issuance of Common Shares for the Acquisition of Emerald Oil North America, Inc.	1,662	13,378,839		13,380,501
Issuance of Common Shares for the Acquisition of Emerald Oil North America, Inc. (in Shares)	1,662,174
Net Loss			(62,296,099)	(62,296,099)
Balance, end of period at Dec. 31, 2012	24,735	180,439,530	(70,170,180)	110,294,085
Balance, end of period (in Shares) at Dec. 31, 2012	24,734,643
Common shares issued for oil and natural gas properties	1,165	6,735,770		6,736,935
Common shares issued for oil and natural gas properties (in Shares)	1,165,015
Stock-based compensation		13,378,158		13,378,158
Restricted Stock Vesting, Net of Tax Withholding	1,012	(2,288,675)		(2,287,663)
Restricted Stock Vesting, Net of Tax Withholding (in Shares)	1,012,260
Net Proceeds from Equity Offering	38,928	238,315,759		238,354,687
Net Proceeds from Equity Offering (in Shares)	38,928,452
Redemption of Preferred Stock and Accretion of Issuance Discount		(17,697,007)		(17,697,007)
Preferred Stock Dividends Paid		(2,582,191)		(2,582,191)
Net Loss			(10,882,895)	(10,882,895)
Balance, end of period at Dec. 31, 2013	65,840	416,301,344	(81,053,075)	335,314,109
Balance, end of period (in Shares) at Dec. 31, 2013	65,840,370
Restricted Stock Grants	1,266	(1,266)
Restricted Stock Grants (in Shares)	1,266,419
Stock-based compensation		11,283,929		11,283,929
Restricted Stock Vesting, Net of Tax Withholding		(4,011,910)		(4,011,910)
Net Loss			(47,179,941)	(52,145,225)
Balance, end of period at Dec. 31, 2014	$ 77,828	$ 455,008,596	$ (128,233,016)	$ 321,888,124
Balance, end of period (in Shares) at Dec. 31, 2014	77,828,613

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REVOLVING CREDIT FACILITY (Narrative) (Details) (USD $)	0 Months Ended	12 Months Ended
	Nov. 20, 2012	Dec. 31, 2014
Line of credit facility maximum commitment	$ 400,000,000	$ 5,000,000
Line of credit		75,000,000
Line of credit facility borrowing amount		250,000,000
Line of credit facility, Interest rate		3.16%
Cash equivalents		10,000,000
Maximum percentage to hedge of proved reserves		60.00%
Percentage to hedge of proved developed produced reserves		80.00%
Percentage of aggregate amount on hedges		100.00%
Credit Facility [Member]
Fronting fee on letter of credit		$ 500
Percentage of fronting fee in letter of credit		0.125%
Ratio of current assets to current liabilities		1.00%
Maximum percentage of total debt to EBITDA		0.04
Minimum [Member]
Line of credit facility, Interest rate		0.375%
Minimum [Member] | Credit Facility [Member]
Line of credit facility, Interest rate		1.75%
Maximum [Member]
Line of credit facility, Interest rate		0.50%
Maximum [Member] | Credit Facility [Member]
Line of credit facility, Interest rate		2.75%
Alternate Base Rate [Member] | Minimum [Member]
Line of credit facility, Interest rate		0.75%
Alternate Base Rate [Member] | Maximum [Member]
Line of credit facility, Interest rate		1.75%
LIBOR [Member] | Minimum [Member]
Line of credit facility, Interest rate		1.75%
LIBOR [Member] | Maximum [Member]
Line of credit facility, Interest rate		2.75%

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SUBSEQUENT EVENTS (Tables)

12 Months Ended

Dec. 31, 2014

Subsequent Events [Abstract]

Schedule of Oil Derivative Swap Contract

Derivative Instruments

On January 6, 2015, the Company settled outstanding NYMEX West Texas Intermediate oil derivative swap contracts on a total of 120,000 barrels of oil, resulting in a cash settlement received of $5,317,300, as indicated below:

Settlement Period	Oil (Bbls)		Settlement Price		Cover Price		Cash Settlement
January 1, 2015 – March 31, 2015		30,000		93.50		51.67		1,255,000
January 1, 2015 – March 31, 2015		36,000		96.05		51.67		1,597,800
January 1, 2015 – March 31, 2015		21,000		97.00		51.67		952,000
January 1, 2015 – March 31, 2015		33,000		97.50		51.67		1,512,500
Total		120,000	$	95.98	$	51.67	$	5,317,300

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INCOME TAXES (Schedule of the Income Tax Expense (Benefit) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Current Income Taxes
Deferred Income Taxes
Federal
State
Total Benefit

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QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)

12 Months Ended

Dec. 31, 2014

Quarterly Financial Information Disclosure [Abstract]

QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)

NOTE 17  QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)

Quarterly data for the years ended December 31, 2014 and 2013 are as follows:

	For the Year Ended December 31, 2014
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Total Revenue	$	18,270,019		$	24,591,325		$	39,911,905		$	29,834,582
Expenses	$	19,556,696		$	23,634,370		$	24,915,171		$	95,069,358
Income (Loss) from Operations	$	(1,286,677	)	$	956,955		$	14,996,734		$	(65,234,776	)
Other Income (Expense), Net	$	(364,410	)	$	(2,907,006	)	$	(1,337,659	)	$	3,031,614
Net Income (Loss) (1)	$	(1,651,087	)	$	(1,950,051	)	$	13,659,075		$	(62,206,162	)
Net Cash Provided By (Used For) Operating Activities	$	10,227,413		$	9,667,326		$	21,301,731		$	15,634,413
Net Cash Provided (Used in) Investing Activities	$	(125,606,786	)	$	(70,850,715	)	$	(277,674,077	)	$	44,863,482
Net Cash Provided (Used in) Financing Activities	$	167,086,647		$	(607,656	)	$	186,469,141		$	(112,377,127	)

(1) The Company recorded impairment of the net capitalized costs of its oil and natural gas properties in the amount of $66,430,000 and debt conversion expense for the fair value of the common shares issued in excess of the common shares underlying the original convertible note indenture agreement in the amount of $10,438,080 in the fourth quarter of 2014.

	For the Year Ended December 31, 2013
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Total Revenue	$	7,449,377		$	11,240,155		$	14,596,398		$	18,038,575
Expenses	$	10,316,386		$	12,248,325		$	5,813,788		$	26,466,746
Income (Loss) from Operations	$	(2,867,009	)	$	(1,008,170	)	$	8,782,610		$	(8,428,171	)
Other Income (Expense), Net	$	(3,617,814	)	$	(714,964	)	$	(524,105	)	$	(2,505,272	)
Net Income (Loss)	$	(6,484,823	)	$	(1,723,134	)	$	8,258,505		$	(10,933,443	)
Net Loss Attributable to Common Stockholders	$	(7,101,261	)	$	(7,388,804	)	$	(5,738,584	)	$	(10,933,443	)
Net Cash Provided By (Used For) Operating Activities	$	377,822		$	1,838,477		$	7,322,429		$	(3,348,288	)
Net Cash Provided (Used in) Investing Activities	$	(13,019,732	)	$	(27,662,815	)	$	12,954,748		$	(47,272,739	)
Net Cash Provided By (Used In) Financing Activities	$	38,243,906		$	62,720,981		$	(23,440,287	)	$	125,348,557

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QUARTERLY RESULTS OF OPERATIONS (UNAUDITED) (Tables)

12 Months Ended

Dec. 31, 2014

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Information

Quarterly data for the years ended December 31, 2014 and 2013 are as follows:

	For the Year Ended December 31, 2014
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Total Revenue	$	18,270,019		$	24,591,325		$	39,911,905		$	29,834,582
Expenses	$	19,556,696		$	23,634,370		$	24,915,171		$	95,069,358
Income (Loss) from Operations	$	(1,286,677	)	$	956,955		$	14,996,734		$	(65,234,776	)
Other Income (Expense), Net	$	(364,410	)	$	(2,907,006	)	$	(1,337,659	)	$	3,031,614
Net Income (Loss) (1)	$	(1,651,087	)	$	(1,950,051	)	$	13,659,075		$	(62,206,162	)
Net Cash Provided By (Used For) Operating Activities	$	10,227,413		$	9,667,326		$	21,301,731		$	15,634,413
Net Cash Provided (Used in) Investing Activities	$	(125,606,786	)	$	(70,850,715	)	$	(277,674,077	)	$	44,863,482
Net Cash Provided (Used in) Financing Activities	$	167,086,647		$	(607,656	)	$	186,469,141		$	(112,377,127	)

(1) The Company recorded impairment of the net capitalized costs of its oil and natural gas properties in the amount of $66,430,000 and debt conversion expense for the fair value of the common shares issued in excess of the common shares underlying the original convertible note indenture agreement in the amount of $10,438,080 in the fourth quarter of 2014.

	For the Year Ended December 31, 2013
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Total Revenue	$	7,449,377		$	11,240,155		$	14,596,398		$	18,038,575
Expenses	$	10,316,386		$	12,248,325		$	5,813,788		$	26,466,746
Income (Loss) from Operations	$	(2,867,009	)	$	(1,008,170	)	$	8,782,610		$	(8,428,171	)
Other Income (Expense), Net	$	(3,617,814	)	$	(714,964	)	$	(524,105	)	$	(2,505,272	)
Net Income (Loss)	$	(6,484,823	)	$	(1,723,134	)	$	8,258,505		$	(10,933,443	)
Net Loss Attributable to Common Stockholders	$	(7,101,261	)	$	(7,388,804	)	$	(5,738,584	)	$	(10,933,443	)
Net Cash Provided By (Used For) Operating Activities	$	377,822		$	1,838,477		$	7,322,429		$	(3,348,288	)
Net Cash Provided (Used in) Investing Activities	$	(13,019,732	)	$	(27,662,815	)	$	12,954,748		$	(47,272,739	)
Net Cash Provided By (Used In) Financing Activities	$	38,243,906		$	62,720,981		$	(23,440,287	)	$	125,348,557

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BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES (Tables)

12 Months Ended

Dec. 31, 2014

Accounting Policies [Abstract]

Schedule of Concentration Risk by Risk Factor

For the years ended December 31, 2014, 2013 and 2012, purchases by the following companies exceeded 10% of the total oil and natural gas revenues of the Company.

	For the Years Ended December 31,
	2014			2013			2012
Customer A		59	%		24	%		—
Customer B		22	%		12	%		—

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FAIR VALUE (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Feb. 19, 2013
Fair value of the warrants upon issuance	$ 2,199,000	$ 15,703,000
Warrant revaluation gain (expense)	(13,504,000)	7,077,000
Fair value of convertible notes	8,180,000
White Deer Energy [Member]
Fair value of the warrants upon issuance				$ 8,626,000

XML

BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2014

Accounting Policies [Abstract]

BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES

NOTE 2  BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES

These consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The accompanying consolidated financial statements include the accounts of Emerald Oil, Inc. and its direct and indirect wholly owned subsidiaries. All significant intercompany accounts and transactions have been eliminated.

Reverse Stock Split

On October 22, 2012, a majority of the Company’s stockholders approved a 1-for-7 reverse stock split pursuant to which all stockholders of record received one share of common stock for each seven shares of common stock owned (subject to minor adjustments as a result of fractional shares). This reverse stock split decreased the issued and outstanding common shares by approximately 140,339,000, the outstanding warrants by approximately 6,700,000 and the outstanding stock options by approximately 4,100,000. GAAP requires that the reverse stock split be applied retrospectively to all periods presented. As a result, all stock, warrant and option transactions described herein have been adjusted to reflect the 1-for-7 reverse stock split.

Cash and Cash Equivalents

The Company considers highly liquid investments with insignificant interest rate risk and original maturities of three months or less to be cash equivalents. Cash equivalents consist primarily of interest-bearing bank accounts and money market funds. The Company’s cash positions represent assets held in checking and money market accounts. These assets are generally available to the Company on a daily or weekly basis and are highly liquid in nature. Due to the balances being greater than the Federal Deposit Insurance Corporation (FDIC) limits of $250,000 per institution per depositor, the Company does not have insurance coverage on the entire amount of its bank deposits. The Company believes this risk to be minimal. In addition, the Company has access 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 consolidated balance sheets totaled $4 million and $21 million at December 31, 2014 and December 31, 2013, respectively.  At December 31, 2014, the $4 million balance related to a drilling commitment agreement entered into pursuant to oil and natural gas leases. As of December 31, 2013, there was an additional $11.0 million of restricted cash related to a portion of proceeds from a leasehold sale held in escrow until finalization of standard due diligence procedures. On February 21, 2014, $8.6 million was released to the Company, with the remaining $2.4 million returned to the buyer for purchase price adjustments.

Accounts Receivable

The Company records estimated oil and natural gas revenue receivable from third parties at its net revenue interest. The Company also reflects costs incurred on behalf of joint interest partners in accounts receivable. Management periodically reviews accounts receivable amounts for collectability and records its allowance for uncollectible receivables under the specific identification method. The Company did not record any allowance for uncollectible receivables during the years ended December 31, 2014, 2013 and 2012.

Concentrations of Credit Risk

Financial instruments that potentially subject us to concentrations of credit risk consist principally of cash and cash equivalents, accounts receivable and derivative contracts. We control our exposure to credit risk associated with these instruments by (i) placing our assets and other financial interests with creditworthy financial institutions, (ii) maintaining policies over credit extension that include the evaluation of customers’ financial condition and monitoring payment history, although we do not have collateral requirements and (iii) netting derivative assets and liabilities for counterparties where we have a legal right of offset.

At December 31, 2014 and 2013, the cash and cash equivalents were concentrated in one financial institution. We periodically assess the financial condition of this institution and believe that any possible credit risk is minimal.

During the year ended December 31, 2014, 81% of the Company’s production was sold to two customers. However, the Company does not believe that the loss of a single purchaser, including these two, would materially affect the Company’s business because there are numerous other purchasers in the area in which the Company sells its production. For the years ended December 31, 2014, 2013 and 2012, purchases by the following companies exceeded 10% of the total oil and natural gas revenues of the Company.

	For the Years Ended December 31,
	2014			2013			2012
Customer A		59	%		24	%		—
Customer B		22	%		12	%		—

Our customers are in the energy industry and they may be similarly affected by changes in economic or other conditions.

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 acquisition, and exploration activities. For the years ended December 31, 2014, 2013 and 2012, the Company capitalized $5,340,034, $3,443,462 and $842,418, respectively, of internal salaries, which included $2,273,656, $1,193,960 and $582,040, 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 interest of $362,688 for the year ended December 31, 2012. The Company did not capitalize interest for the years ended December 31, 2014 and 2013.

Proceeds from property sales will generally be credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. The Company closed property sales during the years ended December 31, 2014 and 2013 in the Williston Basin and Sand Wash Basin (see Note 4 – Oil and Natural Gas Properties). A gain was recognized on one transaction in 2013 that resulted in the sale of a significant portion of proved reserves as of the transaction date and significantly altered the relationship between capitalized costs and proved reserves attributable to the Williston Basin. No gain or loss was recognized on any other sales during the period. The Company engages in acreage trades in the Williston Basin, but these trades are generally for acreage that is similar both in terms of geographic location and potential resource value.

The Company assesses all items classified as 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 years ended December 31, 2014, 2013 and 2012, the Company included $2,979,258, $3,020,485 and $3,625,209, 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. Based on calculated reserves at December 31, 2014, 2013 and 2012, the unamortized costs of the Company’s oil and natural gas properties exceeded the ceiling test limit by $66,430,000, $0 and $51,709,458 respectively. The Company also recognized that oil and natural gas properties exceeded the ceiling test limit as of June 30, 2012 by $10,191,234. As a result, the Company was required to record impairment of the net capitalized costs of its oil and natural gas properties in the amount of $66,430,000, $0 and $61,900,692 for the years ended December 31, 2014, 2013, and 2012, respectively.

Oil and Natural Gas Reserve Quantities

Emerald’s estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Emerald’s reserve estimates are prepared by the independent engineering firm, Netherland, Sewell & Associates, Inc. The estimate of Emerald’s proved reserves as of December 31, 2014, 2013 and 2012 have been prepared and presented in accordance with SEC rules and accounting standards.

Reserves and their relation to estimated future net cash flows impact Emerald’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Emerald prepares its reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines on a quarterly basis. The independent engineering firm described above adheres to the same guidelines when preparing the year-end reserve report. The accuracy of Emerald’s reserve estimates is a function of many factors including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates.

Emerald’s proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil and natural gas eventually recovered.

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. Depreciation expense was $389,551, $144,492 and $53,818 for the years ended December 31, 2014, 2013 and 2012, respectively.

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

Asset Retirement Obligations

The Company records the fair value of a liability for an asset retirement obligation in the period in which the liability 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 proven reserves were not adequate to cover the current imbalance situation. As of December 31, 2014 and 2013, the Company’s natural gas production was in balance, i.e., its cumulative portion of natural gas production taken and sold from wells in which it has an interest equaled the Company’s entitled interest in natural gas production from those wells.

Stock-Based Compensation

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

On May 27, 2011, the stockholders of the Company approved the 2011 Equity Incentive Plan (the “2011 Plan”), under which 714,286 shares of common stock were reserved. On October 22, 2012, the stockholders of the Company approved an amendment to the 2011 Plan to increase the number of shares available for issuance under the 2011 Plan to 3,500,000 shares. 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 9,800,000 shares. The purpose of the 2011 Plan is to promote the success of the Company and its affiliates by facilitating the employment and retention of competent personnel and by furnishing incentives to those officers, directors and employees upon whose efforts the success of the Company and its affiliates will depend to a large degree. It is the intention of the Company to carry out the 2011 Plan through the granting of incentive stock options, nonqualified stock options, restricted stock awards, restricted stock unit awards, performance awards and stock appreciation rights. As of December 31, 2014, 1,211,563 stock options and 3,791,502 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 584,620 nonvested restricted stock units. As of December 31, 2014, there are 4,796,935 shares available for issuance under the 2011 Plan.

Income Taxes

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

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

Net Income (Loss) Per Common Share

Basic net income (loss) per common share is based on the net income (loss) divided by the weighted average number of common shares outstanding during the period. Diluted earnings per share are computed using the weighted average number of common shares plus dilutive common share equivalents outstanding during the period using the treasury stock method. In the computation of diluted earnings per share, excess tax benefits that would be created upon the assumed vesting of nonvested restricted shares or the assumed exercise of stock options (i.e., hypothetical excess tax benefits) are included in the assumed proceeds component of the treasury stock method to the extent that such excess tax benefits are more likely than not to be realized. When a loss from continuing operations exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share. As the Company had losses for the years ended December 31, 2014, 2013 and 2012, the potentially dilutive shares were anti-dilutive and were thus not included in the net loss per share calculation.

 As of December 31, 2014, (i) 584,620 nonvested restricted stock units were issued and outstanding and represented potentially dilutive shares; (ii) 562,673 stock options were issued and exercisable and represented potentially dilutive shares; (iii) 632,006 stock options were granted but were not exercisable and represented potentially dilutive shares; (iv) 5,114,633 warrants were issued and exercisable at an exercise price of $3.02 and represented dilutive shares; (v) 223,293 warrants were issued and exercisable at an exercise price of $6.86 and represented potentially dilutive shares; (vi) 892,858 warrants were issued and exercisable at an exercise price of $49.70 and represented potentially dilutive shares; and (vii) $151.5 million of convertible senior notes convertible into approximately 17,264,958 common shares as of December 31, 2014 and represented potentially dilutive shares.

Derivative and Other Financial Instruments

Commodity Derivative Instruments

The Company has entered into commodity derivative instruments, utilizing oil derivative swap contracts to reduce the effect of price changes on a portion of future oil production. The Company’s commodity derivative instruments are measured at fair value and are included in the consolidated balance sheet as derivative assets and liabilities. Net gains and losses are recorded based on the changes in the fair values of the derivative instruments. The Company’s valuation estimate takes into consideration the counterparties’ credit worthiness, the Company’s credit worthiness, and the time value of money. The consideration of the factors results in an estimated exit price for each derivative asset or liability under a market place participant’s view. Management believes that this approach provides a reasonable, non-biased, verifiable, and consistent methodology for valuing commodity derivative instruments (see Note 14 – Derivative Instruments and Price Risk Management).

Warrant Liability

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

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

New Accounting Pronouncements

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

Use of Estimates

The preparation of consolidated financial statements under GAAP in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates relate to proved oil and natural gas reserve volumes, future development costs, estimates relating to certain oil and natural gas revenues and expenses, fair value of derivative instruments, valuation of share-based compensation 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 prior periods’ reported amounts in order to conform to the current period presentation. These reclassifications did not impact the Company’s net loss, stockholders’ equity or cash flows.

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CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
LIABILITIES AND STOCKHOLDERS' EQUITY
Preferred Stock - Par Value (in Dollars per Share)	$ 0.001	$ 0.001
Preferred Stock - Shares Authorized (in Shares)	20,000,000	20,000,000
Preferred Stock - Shares Issued (in Shares)	5,114,633	5,114,633
Preferred Stock - Shares Outstanding (in Shares)		5,114,633
Preferred Stock - Liquidation Preference Value	$ 5,115	$ 5,115
STOCKHOLDERS' EQUITY
Common Stock, Par Value (in Dollars per Share)	$ 0.001	$ 0.001
Common Stock, Shares Authorized (in Shares)	500,000,000	500,000,000
Common Stock, Shares Issued (in Shares)	77,828,613	65,840,370
Common Stock, Shares Outstanding (in Shares)	77,828,613	65,840,370

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INCOME TAXES

12 Months Ended

Dec. 31, 2014

Income Tax Disclosure [Abstract]

INCOME TAXES

NOTE 12  INCOME TAXES

The Company utilizes the asset and liability approach to measuring deferred tax assets and liabilities based on temporary differences existing at each balance sheet date using currently enacted tax rates in accordance with ASC 740-10-30. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment.

The income tax expense (benefit) for the year ended December 31, 2014, 2013, and 2012 consists of the following:

	2014		2013		2012
Current Income Taxes	$	—	$	—	$	—
Deferred Income Taxes
Federal		—		—		—
State		—		—		—
Total Benefit	$	—	$	—	$	—

The following is a reconciliation of the reported amount of income tax expense (benefit) for the years ended December 31, 2014, 2013 and 2012 to the amount of income tax expenses that would result from applying the statutory rate to pretax income.

Reconciliation of reported amount of income tax expense:

	2014			2013			2012
Loss Before Taxes	$	(52,145,225	)	$	(10,882,895	)	$	(62,296,099	)
Federal Statutory Rate		35	%		35	%		35	%
Benefit Computed at Federal Statutory Rates		(18,250,829	)		(3,809,013	)		(21,803,635	)
State Benefit, Net of Federal Benefit		(923,445	)		(102,503	)		(1,969,364	)
Effects of:
Warrant Revaluation		(4,726,400	)		2,476,950			—
Debt Conversion Expense		3,653,328			—			—
Cancellation of Debt Income		2,646,473			—			—
Nondeductible Expenses		21,155			366,203			10,941
Other		(30,466	)		125,956			(119,872	)
Change in Valuation Allowance		17,610,184			942,407			23,881,930
Reported Benefit	$	—		$	—		$	—

The components of the Company’s deferred tax asset were as follows:

	Year Ended December 31,
	2014			2013
Deferred Tax Assets:
Net Operating Loss Carryforwards (NOLs)	$	41,697,116		$	36,382,177
Stock-based Compensation		5,023,270			3,245,308
Accrued Liability		1,595,333			—
Derivatives		—			323,190
Equity Investments		—			116,886
Oil and Natural Gas Properties		194,329			—
Total Deferred Tax Assets		48,510,048			40,067,561
Deferred Tax Liabilities:		—
Oil and Natural Gas Properties		—			11,093,181
Derivatives		1,877,126			—
Other		55,711			7,353
Total Deferred Tax Liabilities		1,932,837			11,100,534
Less: Valuation Allowance		(46,577,211	)		(28,967,027	)
Total Net Deferred Tax Asset	$	—		$	—

At December 31, 2014, the Company had U.S. Federal NOL carryovers of approximately $117,404,000 which expire from 2029 through 2034. In addition, the Company had state NOL carryovers of approximately $93,502,000, which expire from 2016 through 2034. During 2012, the Company had a IRC Section 382 change of ownership. As a result of the ownership change, the Company's utilization of pre-change U.S. Federal NOL's are subject to an annual limitation amount of approximately $1,754,000. Valuation allowances of $46,577,000 and $28,967,000 have been established to offset the Company's net deferred tax assets as of December 31, 2014 and December 31, 2013, respectively, as the realization of these deferred tax assets is not more likely than not.

Tax benefits are recognized only for tax positions that are more likely than not to be sustained upon examination by tax authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50 percent likely to be realized upon ultimate settlement. Unrecognized tax benefits are tax benefits claimed in the Company's tax returns that do not meet these recognition and measurement standards. The Company has no liabilities for unrecognized tax benefits.

The Company's policy is to recognize potential interest and penalties accrued related to unrecognized tax benefits within income tax expenses. For the years ended December 31, 2014, 2013 and 2012, the Company did not recognize any interest or penalties in its statement of operations, nor did it have any interest or penalties accrued in its balance sheet at December 31, 2014 and 2013 relating to unrecognized benefits.

The tax years 2011 through 2014 remain open to examination for U.S. federal income tax purposes. The Company files tax returns with various state taxing authorities and these returns remain open to examination for the tax years 2010 through 2014.

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Document and Entity Information (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Mar. 10, 2015	Jun. 30, 2014
Document and Entity Information [Abstract]
Entity Registrant Name	Emerald Oil, Inc.
Entity Central Index Key	0001283843
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2014
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock Shares Outstanding		107,904,756
Entity Public Float			$ 357
Entity Well Known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Voluntary Filer	No

XML

FAIR VALUE

12 Months Ended

Dec. 31, 2014

Fair Value Disclosures [Abstract]

FAIR VALUE

NOTE 13 FAIR VALUE

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

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

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

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

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

Fair Value on a Recurring Basis

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

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

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

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

Level 2 assets consist of commodity derivative assets and liabilities (see Note 14 – Derivative Instruments and Price Risk Management).  The fair value of the commodity derivative assets and liabilities are estimated by the Company using the income valuation techniques utilizing an option pricing or discounted cash flow model, as appropriate, which take into account notional quantities, market volatility, market prices, contract parameters and discount rates based on published LIBOR rates. The Company validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those securities trade in active markets.  Assumed credit risk adjustments, based on published credit ratings, public bond yield spreads and credit default swap spreads, are applied to the Company’s commodity derivatives. Significant changes in the quoted forward prices for commodities and changes in market volatility generally leads to corresponding changes in the fair value measurement of the Company’s oil derivative contracts. The fair value of all derivative contracts is reflected on the consolidated balance sheets.

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

Balance, at December 31, 2013	$	(15,703,000	)
Purchases, issuances, and settlements		—
Change in Fair Value of Warrant Liability		13,504,000
Transfers		—
Balance, at December 31, 2014	$	(2,199,000	)

The fair value of the warrants upon issuance to White Deer Energy on February 19, 2013 was recorded at $8,626,000. The warrant revaluation gain (expense) was $13,504,000 and $(7,077,000) for the year ended December 31, 2014 and 2013, respectively, and is included in Other Income/Expense on the accompanying Consolidated Statements of Operations. See discussion of assumptions used in valuing the warrants at Note 14 – 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, 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 $81.8 million at December 31, 2014 based on observed prices for the same or similar types of debt instruments. The Company has classified the valuations of the Convertible Notes and Credit Facility under Level 2 of the fair value hierarchy.

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QUARTERLY RESULTS OF OPERATIONS (UNAUDITED) (Schedule of Quarterly Financial Information) (Details) (USD $)	3 Months Ended												12 Months Ended
	Dec. 31, 2014		Sep. 30, 2014		Jun. 30, 2014		Mar. 31, 2014		Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Quarterly Financial Information Disclosure [Abstract]
Revenue	$ 29,834,582		$ 39,911,905		$ 24,591,325		$ 18,270,019		$ 18,038,575	$ 14,596,398	$ 11,240,155	$ 7,449,377	$ 112,607,831	$ 51,324,505	$ 27,914,546
Expenses	95,069,358		24,915,171		23,634,370		19,556,696		26,466,746	5,813,788	12,248,325	10,316,386	163,175,595	54,845,245	93,326,209
Income (Loss) from Operations	(65,234,776)		14,996,734		956,955		(1,286,677)		(8,428,171)	8,782,610	(1,008,170)	(2,867,009)	(50,567,764)	(3,520,740)	(65,411,663)
Other Income (Expense), Net	3,031,614		(1,337,659)		(2,907,006)		(364,410)		(2,505,272)	(524,105)	(714,964)	(3,617,814)	32,094	2,779	(28,244)
Net Income (Loss)	(62,206,162)	[1]	13,659,075	[1]	(1,950,051)	[1]	(1,651,087)	[1]	(10,933,443)	8,258,505	(1,723,134)	(6,484,823)	(52,145,225)	(10,882,895)	(62,296,099)
Net Loss Attributable to Common Stockholders									(10,933,443)	(5,738,584)	(7,388,804)	(7,101,261)	(52,145,225)	(31,162,092)	(62,296,099)
Net Cash Provided By (Used For) Operating Activities	15,634,413		21,301,731		9,667,326		10,227,413		(3,348,288)	7,322,429	1,838,477	377,822	56,830,883	6,190,440	4,289,767
Net Cash Provided (Used in) Investing Activities	44,863,482		(277,674,077)		(70,850,715)		(125,606,786)		(47,272,739)	12,954,748	(27,662,815)	(13,019,732)	(429,268,096)	(75,000,538)	(66,452,633)
Net Cash Provided By (Used In) Financing Activities	$ (112,377,127)		$ 186,469,141		$ (607,656)		$ 167,086,647		$ 125,348,557	$ (23,440,287)	$ 62,720,981	$ 38,243,906	$ 240,571,005	$ 202,873,157	$ 58,427,978

[1] The Company recorded impairment of the net capitalized costs of its oil and natural gas properties in the amount of $66,430,000 and debt conversion expense for the fair value of the common shares issued in excess of the common shares underlying the original convertible note indenture agreement in the amount of $10,438,080 in the fourth quarter of 2014.

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CONSOLIDATED STATEMENTS OF OPERATIONS (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
REVENUES
Oil Sales	$ 98,532,131	$ 52,609,790	$ 27,264,526
Natural Gas Sales	2,636,460	1,371,250	865,459
Net Gain (Losses) on Commodity Derivatives	11,439,240	(2,656,535)	(215,439)
Total Revenues	112,607,831	51,324,505	27,914,546
OPERATING EXPENSES
Production Expenses	20,559,423	8,520,414	2,727,133
Production Taxes	11,010,300	5,702,521	2,955,015
General and Administrative Expenses	25,186,682	30,507,114	12,903,845
Depletion of Oil and Natural Gas Properties	34,798,218	17,310,059	12,770,718
Impairment of Oil and Natural Gas Properties	66,430,000	0	61,900,692
Depreciation and Amortization	389,551	144,492	53,818
Accretion of Discount on Asset Retirement Obligations	104,803	32,449	14,988
Acquisition Costs	409,712
Early Rig Termination Expense	4,286,906
Gain on Sale of Oil and Natural Gas Properties		(7,371,804)
Total Operating Expenses	163,175,595	54,845,245	93,326,209
LOSS FROM OPERATIONS	(50,567,764)	(3,520,740)	(65,411,663)
OTHER INCOME (EXPENSE)
Interest Expense	(4,675,475)	(287,934)	(2,614,240)
Warrant Revaluation Expense	13,504,000	(7,077,000)
Debt Conversion Expense	(10,438,080)
Gain on Acquisition of Business, Net			5,758,048
Other Income (Expense)	32,094	2,779	(28,244)
Total Other Income (Expense), Net	(1,577,461)	(7,362,155)	3,115,564
INCOME (LOSS) BEFORE INCOME TAXES	(52,145,225)	(10,882,895)	(62,296,099)
INCOME TAX PROVISION
NET LOSS	(52,145,225)	(10,882,895)	(62,296,099)
Less: Preferred Stock Dividends and Deemed Dividends		(20,279,197)
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS	$ (52,145,225)	$ (31,162,092)	$ (62,296,099)
Net Loss Per Common Share - Basic and Diluted (in Dollars per Share)	$ (0.78)	$ (0.75)	$ (4.91)
Weighted Average Shares Outstanding - Basic and Diluted (in Shares)	66,772,458	41,383,277	12,699,544

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STOCK OPTIONS AND WARRANTS

12 Months Ended

Dec. 31, 2014

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

STOCK OPTIONS AND WARRANTS

NOTE 7  STOCK OPTIONS AND WARRANTS

Stock Options

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

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

On July 1, 2014, the Company granted stock options to certain employees to purchase a total of 7,700 shares of common stock exercisable at $7.65 per share. The options vest on an annual basis over 36 months with 2,566 options vesting on July 1, 2015, 2016 and 2017.

On September 22, 2014, the Company granted stock options to certain employees to purchase a total of 19,000 shares of common stock exercisable at $6.80 per share. The options vest on an annual basis over 36 months with 6,333 options vesting on September 22, 2015, 2016 and 2017.

On October 1, 2014 the Company granted stock options to certain employees to purchase a total of 3,400 shares of common stock exercisable at $6.15 per share. The options vest on an annual basis over 36 months with 1,133 options vesting on September 30, 2015, 2016 and 2017.

The total fair value of all stock options granted during the years ended December 31, 2014, 2013 and 2012 were calculated using the Black-Scholes valuation model based on factors present at the time the options were granted.

The impact on the Company’s statement of operations of stock-based compensation expense related to options granted for the years ended December 31, 2014, 2013, and 2012 was $894,303, $1,600,924 and $2,634,681, respectively, net of $0 tax. The Company capitalized $631,992, $1,193,960 and $249,367 in compensation to oil and natural gas properties related to outstanding options for the years ended December 31, 2014, 2013 and 2012, respectively.

A summary of options for the years ended December 31, 2014, 2013, and 2012 is as follows:

	Number of Options			Weighted Average Exercise Price		Remaining Contractual Term (in Years)		Intrinsic Value
Outstanding at January 1, 2012		150,000		$	20.44		7.2		—
Granted		685,713			8.11		—		—
Exercised		—			—		—		—
Forfeited or Expired		—			—		—		—
Outstanding at December 31, 2012		835,713			10.43		7.7		—
Granted		505,301			7.18		—		—
Exercised		(75,000	)		4.43		—		—
Forfeited or Expired		(107,143	)		16.54		—		—
Outstanding at December 31, 2013		1,158,871			8.90		4.8		—
Granted		581,399			7.11		—		—
Exercised		(75,000	)		4.43		—		—
Forfeited or Expired		(470,591	)		8.26		—		—
Outstanding at December 31, 2014		1,194,679		$	8.56		3.7	$	—
Stock Options Exercisable at December 31, 2012		424,997		$	11.39		5.9	$	121,500
Stock Options Exercisable at December 31, 2013		464,273		$	11.12		3.1	$	356,024
Stock Options Exercisable at December 31, 2014		562,673		$	10.03		2.8	$	—

A summary of the status of the Company’s nonvested options as of December 31, 2014 and changes during the year then ended is as follows:

	Number of Options			Weighted-Average Grant-Date Fair Value
Nonvested at December 31, 2012		410,716		$	5.87
Granted		505,301			7.18
Vested		(200,000	)		10.47
Forfeited		(21,430			12.39
Nonvested at December 31, 2013		694,587			7.41
Granted		581,399			7.48
Vested		(373,024	)		7.43
Forfeited		(270,956	)		7.12
Nonvested at December 31, 2014		632,006		$	6.91

For the year ended December 31, 2014, 2013 and 2012, other information pertaining to stock options was as follows:

	2014		2013		2012
Weighted-average per share grant-date fair value of stock options granted	$	7.11	$	4.43	$	4.62
Total intrinsic value of options exercised		257,250		211,250		—
Total grant-date fair value of stock options vested during the year		1,557,619		2,093,999		2,159,307

The following assumptions were used for the Black-Scholes model to value the options granted during the years ended December 31, 2014, 2013 and 2012.

	2014	2013	2012
Risk free rates	0.58% to 1.42%	0.48% to 2.12%	0.17% to 1.20%
Dividend Yield	0%	0%	0%
Expected volatility	56.16% to 67.70%	64.64% to 79.50%	69.70% to 78.99%
Weighted average expected life	3.5 years	5 years	4 years

There was $923,614 of total unrecognized compensation cost related to nonvested stock options granted as of December 31, 2014. At December 31, 2014, the remaining cost is expected to be recognized over a weighted-average period of 0.91 years. These estimates are subject to change based on a variety of future events which include, but are not limited to, changes in estimated forfeiture rates, cancellations and the issuance of new options.

Warrants

The Company has recognized no stock-based compensation expense related to warrants granted for the years ended December 31, 2014, 2013, and 2012. A summary of warrants granted to employees, directors and consultants for the years ended December 31, 2014, 2013 and 2012 is as follows:

	Number of Warrants		Weighted Average Exercise Price		Remaining Contractual Term (in Years)		Intrinsic Value
Outstanding at December 31, 2011		223,293	$	6.86		8.0	$	2,458,251
Granted		—		—		—		—
Exercised		—		—		—		—
Outstanding at December 31, 2012		223,293		6.86		7.0		—
Granted		—		—		—		—
Exercised		—		—		—		—
Outstanding at December 31, 2013		223,293		6.86		6.0		178,634
Granted		—		—		—		—
Exercised		—		—		—		—
Outstanding at December 31, 2014		223,293	$	6.86		5.0	$	—

On February 8, 2011, in conjunction with the sale of 1,785,714 shares of common stock (see Note 6), the Company issued investors warrants to purchase a total of 892,858 shares of common stock exercisable at $49.70 per share.

For the years ended December 31, 2014, 2013 and 2012, other information pertaining to warrants was as follows:

	2014		2013 (1)		2012
Weighted-average grant-date fair value of warrants granted	$	—	$	1.69	$	—
Total intrinsic value of warrants exercised	$	—	$	—	$	—
Total grant-date fair value of warrants vested during the year	$	—	$	—	$	—

(1) See Note 6 – Common and Preferred Stock – Preferred Stock for details on the warrants issued on February 19, 2013 associated with the preferred stock transaction.

The following assumptions were used for the Black-Scholes model to value the warrants granted during the years ended December 31, 2014, 2013 and 2012.

	2014		2013 (1)		2012
Risk free rates		—		—		—
Dividend yield		—		—		—
Expected volatility		—		—		—
Weighted average expected life		—		—		—

(1) See Note 14 – Derivative Instruments and Price Risk Management – Warrant Liability for the method and assumptions used to value the warrants issued on February 19, 2013 associated with the preferred stock transaction.

The table below reflects the status of warrants outstanding at December 31, 2014:

	Warrants		Exercise Price		Expiration Date
December 1, 2009		37,216	$	6.86	December 1, 2019
December 31, 2009		186,077	$	6.86	December 31, 2019
February 8, 2011		892,858	$	49.70	February 8, 2016
February 19, 2013 (1)		5,114,633	$	3.02	December 31, 2019
Total		6,230,784

(1) See Note 16 – Subsequent Events for details on the warrant price adjustment subsequent to December 31, 2014.

No warrants expired or were forfeited during the year ended December 31, 2014. All of the compensation expense related to the applicable vested warrants issued to employees has been expensed by the Company prior to 2012. All warrants outstanding were exercisable at December 31, 2014.

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PREFERRED AND COMMON STOCK

12 Months Ended

Dec. 31, 2014

Stockholders' Equity Note [Abstract]

PREFERRED AND COMMON STOCK

NOTE 6  PREFERRED AND COMMON STOCK

Preferred Stock

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

On various dates throughout 2013, the Company redeemed all of the outstanding shares of Series A Preferred Stock, including principal of $50,000,000 and redemption premiums of $6,250,000, and no shares of Series A Preferred Stock remained outstanding as of December 31, 2014. For each redemption, the redemption premium was treated as a dividend and recorded as a return of equity to White Deer Energy through a charge to the Company’s additional paid-in capital. The Company paid no dividends during the year ended December 31, 2014 and $2,582,191 for the year ended December 31, 2013. No dividends were paid prior to 2013.

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

The warrants entitle White Deer Energy to acquire 5,114,633 shares of common stock at an initial exercise price of $5.77 per share and surrendering an equal number of shares of Series B Preferred Stock to the Company. In December 2014, the Company issued 10,721,824 common shares below the initial warrant exercise price of $5.77 to extinguish $21,000,000 of Convertible Notes. As a result of the issuance, the warrant exercise price was reduced to $3.02 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, Note 14 – Derivative Instruments and Price Risk Management – Warrant Liability and Note 16 – Subsequent Events for further discussion of the warrant liability valuation and further reduction of the warrant exercise price subsequent to year end.

Upon a change of control or Liquidation Event, as defined in the Securities Purchase Agreement, the Investor has the right, but not the obligation, to elect to receive from the Company, in exchange for all, but not less than all, shares of Series A and Series B Preferred Stock and the warrants issued pursuant to the Securities Purchase Agreement and shares of common stock issued upon exercise thereof that are then held by the Investor, an additional cash payment necessary to achieve a minimum internal rate of return of 25% as calculated as defined. The calculation took into account all cash inflows from and cash outflows to the Investor. Upon the final Series A Preferred Stock redemption on October 15, 2013, the minimum internal rate of return was achieved and no additional cash payment was necessary.

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 partial redemptions of preferred stock on June 20, 2013, August 30, 2013 and October 15, 2013. There was no issuance discount remaining as of December 31, 2013 or 2014.

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

	December 31, 2014		December 31, 2013		February 19, 2013 (issuance date)
Series A Preferred Stock	$	—	$	—	$	41,369,000
Series B Preferred Stock		5,000		5,000		5,000
Warrant Liability		2,199,000		15,703,000		8,626,000
Total	$	2,204,000	$	15,708,000	$	50,000,000

Equity Issuances

On February 8, 2011, the Company completed a private placement of 1,785,714 units, which consisted of one share of common stock and a warrant to purchase one-half of a share of common stock, at a subscription price of $28.00 per unit for total gross proceeds of $50 million. The exercise price of the warrants is $49.70 per whole share of common stock for a period of five years from the date of closing. The total number of shares that are issuable upon exercise of warrants is 892,857. The Company incurred costs of $3,397,749 related to this transaction, which costs were netted against the proceeds of the transaction through additional paid-in capital.

On September 28, 2012, the Company completed a public offering of 13,392,857 shares of common stock at a price of $5.60 per share for total gross proceeds of $75 million.  The Company incurred costs of approximately $5.3 million related to this transaction, which costs were netted against the proceeds of the transaction through additional paid-in capital. The underwriters elected to exercise the over-allotment option to sell an additional 484,698 shares of common stock at $5.60 per share. The gross proceeds from the over-allotment exercise were $2.7 million, and the net proceeds are approximately $2.5 million after deducting underwriting discounts and commissions. The over-allotment exercise closed on October 26, 2012.

The Company issued 851,315 and 313,700 shares of its common stock related to two acreage acquisitions completed on January 9, 2013 and February 4, 2013, respectively. See Note 4 – Oil and Natural Gas Properties – Acquisitions for additional details.

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

On June 4, 2013, the Company completed a private placement of 2,785,600 shares of common stock at a price of $5.87 per share for net proceeds of approximately $16.2 million after deducting placement agent fees of approximately $0.2 million. The Company’s Audit Committee, which consisted solely of independent directors, reviewed and approved this transaction. The issuance of the common stock was made in reliance upon an exemption from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(2) thereof, which exempts transactions by an issuer not involving any public offering.

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

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

In December 2014, the Company issued 10,721,824 common shares to extinguish $21,000,000 of Convertible Notes. As a result of the issuance, the warrant exercise price was reduced to $3.02 per share pursuant to a formula provided in the original warrant agreement. The Company recognized $10,438,080 of debt conversion expense for the fair value of the common shares issued in excess of the common shares underlying the original convertible note indenture agreement. See Note 9 – Convertible Notes and Note 16 – Subsequent Events for further discussion of the convertible notes.

Restricted Stock Awards and Restricted Stock Unit Awards

The Company incurred compensation expense associated with restricted stock and restricted stock units granted of $10,457,009, $10,903,696 and $4,684,009 for the years ended December 31, 2014, 2013 and 2012, respectively. There were 584,620 nonvested restricted stock units and $2,124,950 associated remaining unrecognized compensation expense as of December 31, 2014 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 of $1,641,664, $851,979 and $332,673 to oil and natural gas properties for the years ended December 31, 2014, 2013 and 2012, respectively. Approximately $919,633 of the compensation expense associated with restricted stock and restricted stock units during the year ended December 31, 2014 related to the modification and accelerated vesting of restricted stock unit grants associated with severance to a prior officer of the Company. A total of 213,228 restricted stock units associated with the severance vested on September 10, 2014. There is no remaining unamortized expense associated with the severance as of December 31, 2014. A summary of the restricted stock units and restricted stock shares outstanding is as follows:

	Number of Shares			Weighted Average Grant Date Fair Value
Non-vested restricted stock and restricted stock units at January 1, 2012		—		$	—
Granted		1,919,135			4.93
Canceled		—			—
Forfeited		(53,577	)		21.00
Vested		(17,857	)		21.00
Non-vested restricted stock and restricted stock units at December 31, 2012		1,847,701			4.31
Granted		1,242,505			7.10
Canceled		(70,642	)		4.19
Forfeited		(302,016	)		4.86
Vested		(635,361	)		4.88
Non-vested restricted stock and restricted stock units at December 31, 2013		2,082,187			5.73
Granted		264,134			7.48
Canceled		(73,204	)		7.23
Forfeited		(639,299	)		5.48
Vested		(1,049,198	)		5.36
Non-vested restricted stock and restricted stock units at December 31, 2014		584,620		$	7.27

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BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2014

Accounting Policies [Abstract]

Reverse Stock Split, Policy

Reverse Stock Split

On October 22, 2012, a majority of the Company’s stockholders approved a 1-for-7 reverse stock split pursuant to which all stockholders of record received one share of common stock for each seven shares of common stock owned (subject to minor adjustments as a result of fractional shares). This reverse stock split decreased the issued and outstanding common shares by approximately 140,339,000, the outstanding warrants by approximately 6,700,000 and the outstanding stock options by approximately 4,100,000. GAAP requires that the reverse stock split be applied retrospectively to all periods presented. As a result, all stock, warrant and option transactions described herein have been adjusted to reflect the 1-for-7 reverse stock split.

Cash and Cash Equivalents, Policy

Cash and Cash Equivalents

The Company considers highly liquid investments with insignificant interest rate risk and original maturities of three months or less to be cash equivalents. Cash equivalents consist primarily of interest-bearing bank accounts and money market funds. The Company’s cash positions represent assets held in checking and money market accounts. These assets are generally available to the Company on a daily or weekly basis and are highly liquid in nature. Due to the balances being greater than the Federal Deposit Insurance Corporation (FDIC) limits of $250,000 per institution per depositor, the Company does not have insurance coverage on the entire amount of its bank deposits. The Company believes this risk to be minimal. In addition, the Company has access 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, Policy

Restricted Cash

Restricted cash included in current and long-term assets on the consolidated balance sheets totaled $4 million and $21 million at December 31, 2014 and December 31, 2013, respectively.  At December 31, 2014, the $4 million balance related to a drilling commitment agreement entered into pursuant to oil and natural gas leases. As of December 31, 2013, there was an additional $11.0 million of restricted cash related to a portion of proceeds from a leasehold sale held in escrow until finalization of standard due diligence procedures. On February 21, 2014, $8.6 million was released to the Company, with the remaining $2.4 million returned to the buyer for purchase price adjustments.

Accounts Receivable, Policy

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 years ended December 31, 2014, 2013 and 2012.

Concentrations of Credit Risk, Policy

Concentrations of Credit Risk

Financial instruments that potentially subject us to concentrations of credit risk consist principally of cash and cash equivalents, accounts receivable and derivative contracts. We control our exposure to credit risk associated with these instruments by (i) placing our assets and other financial interests with creditworthy financial institutions, (ii) maintaining policies over credit extension that include the evaluation of customers’ financial condition and monitoring payment history, although we do not have collateral requirements and (iii) netting derivative assets and liabilities for counterparties where we have a legal right of offset.

At December 31, 2014 and 2013, the cash and cash equivalents were concentrated in one financial institution. We periodically assess the financial condition of this institution and believe that any possible credit risk is minimal.

During the year ended December 31, 2014, 81% of the Company’s production was sold to two customers. However, the Company does not believe that the loss of a single purchaser, including these two, would materially affect the Company’s business because there are numerous other purchasers in the area in which the Company sells its production. For the years ended December 31, 2014, 2013 and 2012, purchases by the following companies exceeded 10% of the total oil and natural gas revenues of the Company.

	For the Years Ended December 31,
	2014			2013			2012
Customer A		59	%		24	%		—
Customer B		22	%		12	%		—

Our customers are in the energy industry and they may be similarly affected by changes in economic or other conditions.

Full Cost Method, Policy

Full Cost Method

The Company follows the full cost method of accounting for oil and natural gas operations whereby all costs related to the exploration and development of oil and natural gas properties are initially capitalized into a single cost center (“full cost pool”). Such costs include land acquisition costs, a portion of employee salaries related to property development, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisition, and exploration activities. For the years ended December 31, 2014, 2013 and 2012, the Company capitalized $5,340,034, $3,443,462 and $842,418, respectively, of internal salaries, which included $2,273,656, $1,193,960 and $582,040, 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 interest of $362,688 for the year ended December 31, 2012. The Company did not capitalize interest for the years ended December 31, 2014 and 2013.

Proceeds from property sales will generally be credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. The Company closed property sales during the years ended December 31, 2014 and 2013 in the Williston Basin and Sand Wash Basin (see Note 4 – Oil and Natural Gas Properties). A gain was recognized on one transaction in 2013 that resulted in the sale of a significant portion of proved reserves as of the transaction date and significantly altered the relationship between capitalized costs and proved reserves attributable to the Williston Basin. No gain or loss was recognized on any other sales during the period. The Company engages in acreage trades in the Williston Basin, but these trades are generally for acreage that is similar both in terms of geographic location and potential resource value.

The Company assesses all items classified as 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 years ended December 31, 2014, 2013 and 2012, the Company included $2,979,258, $3,020,485 and $3,625,209, 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. Based on calculated reserves at December 31, 2014, 2013 and 2012, the unamortized costs of the Company’s oil and natural gas properties exceeded the ceiling test limit by $66,430,000, $0 and $51,709,458 respectively. The Company also recognized that oil and natural gas properties exceeded the ceiling test limit as of June 30, 2012 by $10,191,234. As a result, the Company was required to record impairment of the net capitalized costs of its oil and natural gas properties in the amount of $66,430,000, $0 and $61,900,692 for the years ended December 31, 2014, 2013, and 2012, respectively.

Oil and Natural Gas Reserve Quantities, Policy

Oil and Natural Gas Reserve Quantities

Emerald’s estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Emerald’s reserve estimates are prepared by the independent engineering firm, Netherland, Sewell & Associates, Inc. The estimate of Emerald’s proved reserves as of December 31, 2014, 2013 and 2012 have been prepared and presented in accordance with SEC rules and accounting standards.

Reserves and their relation to estimated future net cash flows impact Emerald’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Emerald prepares its reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines on a quarterly basis. The independent engineering firm described above adheres to the same guidelines when preparing the year-end reserve report. The accuracy of Emerald’s reserve estimates is a function of many factors including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates.

Emerald’s proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil and natural gas eventually recovered.

Other Property and Equipment, Policy

Other Property and Equipment

Property and equipment that are not oil and natural gas properties are recorded at cost and depreciated using the straight-line method over their estimated useful lives of three to seven years. Expenditures for replacements, renewals, and betterments are capitalized. Maintenance and repairs are charged to expense as incurred. Depreciation expense was $389,551, $144,492 and $53,818 for the years ended December 31, 2014, 2013 and 2012, respectively.

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

Asset Retirement Obligations, Policy

Asset Retirement Obligations

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

Revenue Recognition and Natural Gas Balancing, Policy

Revenue Recognition and Natural Gas Balancing

The Company recognizes oil and natural gas revenues from its interests in producing wells when production is delivered and title has transferred to the purchaser, to the extent the selling price is reasonably determinable. The Company uses the sales method of accounting for balancing of natural gas production and would recognize a liability if the existing proven reserves were not adequate to cover the current imbalance situation. As of December 31, 2014 and 2013, the Company’s natural gas production was in balance, i.e., its cumulative portion of natural gas production taken and sold from wells in which it has an interest equaled the Company’s entitled interest in natural gas production from those wells.

Stock-Based Compensation, Policy

Stock-Based Compensation

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

On May 27, 2011, the stockholders of the Company approved the 2011 Equity Incentive Plan (the “2011 Plan”), under which 714,286 shares of common stock were reserved. On October 22, 2012, the stockholders of the Company approved an amendment to the 2011 Plan to increase the number of shares available for issuance under the 2011 Plan to 3,500,000 shares. 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 9,800,000 shares. The purpose of the 2011 Plan is to promote the success of the Company and its affiliates by facilitating the employment and retention of competent personnel and by furnishing incentives to those officers, directors and employees upon whose efforts the success of the Company and its affiliates will depend to a large degree. It is the intention of the Company to carry out the 2011 Plan through the granting of incentive stock options, nonqualified stock options, restricted stock awards, restricted stock unit awards, performance awards and stock appreciation rights. As of December 31, 2014, 1,211,563 stock options and 3,791,502 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 584,620 nonvested restricted stock units. As of December 31, 2014, there are 4,796,935 shares available for issuance under the 2011 Plan.

Income Taxes, Policy

Income Taxes

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

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

Net Income (Loss) Per Common Share, Policy

Net Income (Loss) Per Common Share

Basic net income (loss) per common share is based on the net income (loss) divided by the weighted average number of common shares outstanding during the period. Diluted earnings per share are computed using the weighted average number of common shares plus dilutive common share equivalents outstanding during the period using the treasury stock method. In the computation of diluted earnings per share, excess tax benefits that would be created upon the assumed vesting of nonvested restricted shares or the assumed exercise of stock options (i.e., hypothetical excess tax benefits) are included in the assumed proceeds component of the treasury stock method to the extent that such excess tax benefits are more likely than not to be realized. When a loss from continuing operations exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share. As the Company had losses for the years ended December 31, 2014, 2013 and 2012, the potentially dilutive shares were anti-dilutive and were thus not included in the net loss per share calculation.

 As of December 31, 2014, (i) 584,620 nonvested restricted stock units were issued and outstanding and represented potentially dilutive shares; (ii) 562,673 stock options were issued and exercisable and represented potentially dilutive shares; (iii) 632,006 stock options were granted but were not exercisable and represented potentially dilutive shares; (iv) 5,114,633 warrants were issued and exercisable at an exercise price of $3.02 and represented dilutive shares; (v) 223,293 warrants were issued and exercisable at an exercise price of $6.86 and represented potentially dilutive shares; (vi) 892,858 warrants were issued and exercisable at an exercise price of $49.70 and represented potentially dilutive shares; and (vii) $151.5 million of convertible senior notes convertible into approximately 17,264,958 common shares as of December 31, 2014 and represented potentially dilutive shares.

Derivative and Other Financial Instruments, Policy

Derivative and Other Financial Instruments

Commodity Derivative Instruments

The Company has entered into commodity derivative instruments, utilizing oil derivative swap contracts to reduce the effect of price changes on a portion of future oil production. The Company’s commodity derivative instruments are measured at fair value and are included in the consolidated balance sheet as derivative assets and liabilities. Net gains and losses are recorded based on the changes in the fair values of the derivative instruments. The Company’s valuation estimate takes into consideration the counterparties’ credit worthiness, the Company’s credit worthiness, and the time value of money. The consideration of the factors results in an estimated exit price for each derivative asset or liability under a market place participant’s view. Management believes that this approach provides a reasonable, non-biased, verifiable, and consistent methodology for valuing commodity derivative instruments (see Note 14 – Derivative Instruments and Price Risk Management).

Warrant Liability

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

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

New Accounting Pronouncements, Policy

New Accounting Pronouncements

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

Use of Estimates, Policy

Use of Estimates

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

Industry Segment and Geographic Information, Policy

Industry Segment and Geographic Information

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

Reclassifications, Policy

Reclassifications

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

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DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT

12 Months Ended

Dec. 31, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT

NOTE 14 DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT

Commodity

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

All derivative positions are carried at their fair value on the 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 and therefore the current asset and liability are netted on the consolidated balance sheet and the non-current asset and liability are netted on the consolidated balance sheet.

The following table reflects open commodity swap contracts as of December 31, 2014, the associated volumes and the corresponding weighted average NYMEX reference price:

Settlement Period	Oil (Bbls)		Fixed Price
Oil Swaps
January 1, 2015 – March 31, 2015		30,000	$	93.50
January 1, 2015 – March 31, 2015		36,000		96.05
January 1, 2015 – March 31, 2015		21,000		97.00
January 1, 2015 – March 31, 2015		33,000		97.50
2015 Total/Average		120,000	$	95.98

On January 5, 2015, the company settled its outstanding NYMEX West Texas Intermediate oil derivative swap contracts on a total of 120,000 barrels of oil, resulting in a cash settlement received of $5,317,300.

The following table sets forth a reconciliation of the changes in fair value of the Company’s commodity derivatives for the years ended December 31, 2014 and 2013.

	2014			2013
Beginning fair value of commodity derivatives	$	(853,005	)	$	(181,248	)
Total gains (losses) on oil derivatives		11,439,240			(2,656,535	)
Cash settlements (received) paid on oil derivatives		(5,542,110	)		1,984,778
Ending fair value of commodity derivatives	$	5,044,125		$	(853,005	)

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

Warrant Liability

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

The Company estimated the value of the warrants issued with the Securities Purchase Agreement on the date of issuance to be $8,626,000, or $1.69 per warrant, using the Monte Carlo model with the following assumptions: a term of 1,798 trading days, exercise price of $5.77, volatility rate of 40%, and a risk-free interest rate of 1.38%. The Company remeasured the warrants as of December 31, 2014, using the same Monte Carlo model, using the following assumptions: a term of 1,255 trading days, exercise price of $3.02, stock price of $1.20, average volatility rate of 61%, and a risk-free interest rate of 1.65%. As of December 31, 2014, the fair value of the warrants was $2,199,000, or $0.43 per warrant, and was recorded as a liability on the accompanying consolidated balance sheets. An increase in any of the variables would cause an increase in the fair value of the warrants. Likewise, a decrease in any variable would cause a decrease in the value of the warrants.

At December 31, 2014, the Company had derivative financial instruments recorded on the consolidated balance sheet as set forth below:

Type of Contract	Balance Sheet Location
Derivative Assets (Liabilities):
Swap Contracts	Current assets	$	5,044,125
Warrant Liability	Non-current liabilities		(2,199,000	)
Total Derivative Liabilities		$	2,845,125

At December 31, 2013, the Company had derivative financial instruments recorded on the consolidated balance sheet as set forth below:

Type of Contract	Balance Sheet Location
Derivative Assets (Liabilities):
Swap Contracts	Current liabilities	$	(921,401	)
Swap Contracts	Non-current assets		68,396
Warrant Liability	Non-current liabilities		(15,703,000	)
Total Derivative Liabilities		$	(16,556,005	)

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ASSET RETIREMENT OBLIGATION

12 Months Ended

Dec. 31, 2014

Asset Retirement Obligation Disclosure [Abstract]

ASSET RETIREMENT OBLIGATION

NOTE 10  ASSET RETIREMENT OBLIGATION

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

The following table summarizes the Company’s asset retirement obligation transactions for the years ended December 31, 2014, 2013 and 2012:

	2014			2013			2012
Beginning Asset Retirement Obligation	$	692,137		$	296,074		$	116,119
Revision of Previous Estimates		148,968			165,968			—
Liabilities Incurred or Acquired		1,817,939			510,271			164,967
Accretion of Discount on Asset Retirement Obligations		104,803			32,449			14,988
Wells Settled through P&A		(72,555	)		—			—
Liabilities Associated with Properties Sold		(19,317	)		(312,625	)		—
Ending Asset Retirement Obligation	$	2,671,975		$	692,137		$	296,074

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CONVERTIBLE NOTES (Narrative) (Details) (USD $)	12 Months Ended			1 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2014	Mar. 24, 2014
Debt Instrument [Line Items]
Conversion debt expense fair value	$ 10,438,080
Convertible Debt [Member]
Debt Instrument [Line Items]
Convertible notes principal amount	1,000			1,000	172,500,000
Percentage of convertible notes	2.00%			2.00%	2.00%
Convertible notes maturity date	Apr. 01, 2019
Shares issued for convertible notes	17,264,958			10,721,824
Private placement, proceeds	166,900,000
Convertible notes initially share issued	113.9601
Convertible notes, conversion rate, price per share (in Dollars per Share)	$ 8.78			$ 8.78
Convertible notes, fundamental change purchase price percentage	100.00%
Convertible notes, event of default, minimum percent of outstanding principal required among noteholders to trigger prepayment demand under event of default (in Percent)	25.00%
Shares issued for convertible notes, value				21,000,000
Convertible notes underlying common shares				2,393,162
Conversion debt expense fair value				$ 10,438,080

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REVOLVING CREDIT FACILITY

12 Months Ended

Dec. 31, 2014

Line of Credit Facility [Abstract]

REVOLVING CREDIT FACILITY

NOTE 8 REVOLVING CREDIT FACILITY

Wells Fargo Facility

On November 20, 2012, the Company entered into a senior secured revolving credit facility (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. As of December 31, 2014, the Company had drawn $75.0 million toward its $250 million borrowing base under the Credit Facility.

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

The annual interest cost under the Credit Facility, which is dependent upon the percentage of the borrowing base utilized, is, at the Company’s option, based on either the Alternate Base Rate (as defined under the terms of the Credit Facility) plus 0.75% to 1.75% or the London Interbank Offer Rate (LIBOR) plus 1.75% to 2.75%; provided, in no event may the interest rate exceed the maximum interest rate allowed by any current or future law.  Interest on ABR Loans is due and payable on a quarterly basis, and interest on Eurodollar Loans is due and payable, at the Company’s option, at one-, two-, three-, six- (or in some cases nine- or twelve-) month intervals. The Company also pays a commitment fee ranging from 0.375% to 0.5%, depending on the percentage of the borrowing base utilized. As of December 31, 2014, the annual interest rate on the Credit Facility was 3.16%.

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 December 31, 2014, the Company has not obtained any letters of credit under the Credit Facility.

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

The Credit Facility contains customary covenants that include, among other things: limitations on the ability of the Company to incur or guarantee additional indebtedness; create liens; pay dividends on or repurchase stock; make certain types of investments; enter into transactions with affiliates; and sell assets or merge with other companies. The Credit Facility also requires compliance with certain financial covenants, including, (a) a ratio of current assets to current liabilities of at least 1.00 to 1.00, (b) a maximum ratio of total debt to EBITDA for the preceding four fiscal quarters of no more than 4.00 to 1.00. For any fiscal quarter ending in calendar year 2014, total debt is reduced by cash equivalents less $10,000,000 for purposes of calculating the total debt to EBITDA ratio. The Company was in compliance with all covenants under the Credit Facility as of December 31, 2014.

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

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SENIOR SECURED PROMISSORY NOTES

12 Months Ended

Dec. 31, 2014

Debt Disclosure [Abstract]

SENIOR SECURED PROMISSORY NOTES

NOTE 9 CONVERTIBLE NOTES

On March 24, 2014, the Company completed a private placement of $172.5 million in aggregate principal amount of 2.0% Convertible Notes (the “Convertible Notes”), and entered into an indenture (the “Indenture”) governing the Convertible Notes, with U.S. Bank National Association, as trustee (the “Trustee”). The Convertible Notes accrue interest at a rate of 2.00% per year, payable semiannually in arrears on April 1 and October 1 of each year, beginning on October 1, 2014. The Convertible Notes mature on April 1, 2019. The Convertible Notes are the Company’s unsecured senior obligations and are equal in right of payment to the Company’s existing and future senior indebtedness. The Convertible Notes were convertible into approximately 17,264,958 shares of common stock as of December 31, 2014. However, the Company does not believe further conversion will take place due to the term remaining on the Convertible Notes, and in the event of conversion, holders would forgo all future interest payments. As a result, the Convertible Notes have been classified as long-term debt as of December 31, 2014.

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

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

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

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

The Indenture contains customary terms and covenants and events of default. If an Event of Default (as defined in the Indenture) occurs and is continuing, the Trustee or the holders of at least 25% in aggregate principal amount of the then outstanding Convertible Notes may declare by written notice all the Convertible Notes to be immediately due and payable in full. The Company was in compliance with all covenants as of December 31, 2014.

In December 2014, the Company issued 10,721,824 common shares to extinguish $21,000,000 of Convertible Notes. The Convertible Notes had 2,393,162 underlying common shares under the terms of the original indenture agreement. As a result, the Company recognized $10,438,080 of debt conversion expense for the fair value of the common shares issued in excess of the common shares underlying the original convertible note indenture agreement.

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ACCRUED LIABILITIES

12 Months Ended

Dec. 31, 2014

Payables and Accruals [Abstract]

ACCRUED LIABILITIES

NOTE 11 ACCRUED LIABILITIES

The Company’s accrued liabilities consist of the following:

	December 31,
	2014		2013
Accrued Transaction Adjustments	$	249,764	$	2,067,150
Oil and Natural Gas Revenue Payable		4,667,935		7,451,394
Other General and Administrative Expenses		6,350,132		2,303,185
Total Accrued Liabilities	$	11,267,831	$	11,821,729

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INCOME TAXES (Narrative) (Details) (USD $)

12 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Operating Loss Carryforwards [Line Items]

U.S. Federal NOLs subject to an annual limitation

$ 1,754,000

Valuation Allowance

46,577,211

28,967,027

Penalties and interest expense

Penalties and interest accrued

Federal [Member]

Operating Loss Carryforwards [Line Items]

Net operating loss (NOL) carryovers

117,404,000

Operating loss carryforward, expiration date

2029 through 2034

State [Member]

Operating Loss Carryforwards [Line Items]

Net operating loss (NOL) carryovers

$ 93,502,000

Operating loss carryforward, expiration date

2016 through 2034

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INCOME TAXES (Schedule of Reported Income Tax Expense (Benefit) Reconciliation) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Loss Before Taxes	$ (52,145,225)	$ (10,882,895)	$ (62,296,099)
Federal Statutory Rate	35.00%	35.00%	35.00%
Benefit Computed at Federal Statutory Rates	(18,250,829)	(3,809,013)	(21,803,635)
State Benefit, Net of Federal Benefit	(923,445)	(102,503)	(1,969,364)
Effects of:
Warrant Revaluation	(4,726,400)	2,476,950
Debt Conversion Expense	3,653,328
Cancellation of Debt Income	2,646,473
Nondeductible expenses	21,155	366,203	10,941
Other	(30,466)	125,956	(119,872)
Change in Valuation Allowance	17,610,184	942,407	23,881,930
Total Benefit

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ACCRUED LIABILITIES (Schedule of Accrued Liabilities) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Payables and Accruals [Abstract]
Accrued Transaction Adjustments	$ 249,764	$ 2,067,150
Oil and Natural Gas Revenue Payable	4,667,935	7,451,394
Other General and Administrative Expenses	6,350,132	2,303,185
Total Accrued Liabilities	$ 11,267,831	$ 11,821,729

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COMMITMENTS AND CONTINGENCIES (Tables)

12 Months Ended

Dec. 31, 2014

Commitments and Contingencies Disclosure [Abstract]

Minimum Rental Commitments

At December 31, 2014, the minimum rental commitments under all non-cancelable operating leases with initial or remaining terms of more than one year are as follows:

	Payment due for the year ended December 31,
Contractual Obligations	Total		2015		2016		2017		2018		2019
Office Leases (1)	$	2,320,441	$	464,088	$	472,630	$	481,171	$	489,713	$	412,839

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STOCK OPTIONS AND WARRANTS (Schedule of Stock Options, Roll Forward) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Sep. 30, 2014	Sep. 22, 2014	Jun. 30, 2014	Mar. 31, 2014	Jan. 10, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock options outstanding at beginning of period (in Shares)	1,158,871	835,713	150,000
Stock options granted (in Shares)	581,399	505,301	685,713
Stock options exercised (in Shares)	(75,000)	(75,000)
Stock options forfeited or expired (in Shares)	(470,591)	(107,143)
Stock options outstanding at end of period (in Shares)	1,194,679	1,158,871	835,713	150,000
Stock options exercisable at end of period (in Shares)	562,673	464,273	424,997
Stock options outstanding weighted average exercise price at beginning of period (in Dollars per Share)	$ 8.90	$ 10.43	$ 20.44
Stock options granted weighted average exercise price (in Dollars per Share)	$ 7.11	$ 7.18	$ 8.11
Stock options exercised weighted average exercise price (in Dollars per Share)	$ 4.43	$ 4.43
Stock options forfeited or expired weighted average exercise price (in Dollars per Share)	$ 8.26	$ 16.54
Stock options outstanding weighted average exercise price at end of period (in Dollars per Share)	$ 8.56	$ 8.90	$ 10.43	$ 20.44
Stock options exercisable, weighted average exercise price at end of period (in Dollars per Share)	$ 10.03	$ 11.12	$ 11.39		$ 6.15	$ 6.80	$ 7.65	$ 6.69	$ 7.48
Stock options outstanding, Remaining contractual term (in Years) (in Duration)	3 years 8 months 12 days	4 years 9 months 18 days	7 years 8 months 12 days	7 years 2 months 12 days
Stock options exercisable, Remaining contractual term (in Years) (in Duration)	2 years 9 months 18 days	3 years 1 month 6 days	5 years 10 months 24 days
Stock options outstanding intrinsic value
Stock options exercisable intrinsic value		$ 356,024	$ 121,500

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SUBSEQUENT EVENTS

12 Months Ended

Dec. 31, 2014

Subsequent Events [Abstract]

SUBSEQUENT EVENTS

NOTE 16 SUBSEQUENT EVENTS

Equity Offering

On February 11, 2015, the Company completed a public offering of 24,553,571 shares of common stock at a price of $1.12 per share for total net proceeds of approximately $26.5 million. On February 19, 2015 the underwriters elected to exercise the over-allotment option to sell an additional 2,605,536 shares of common stock at $1.12 per share. The net proceeds from the over-allotment exercise were $2.8 million.

Warrant Exercise Price Adjustment

As a result of the sale of common shares completed on February 11, 2015, the outstanding warrants held by White Deer were adjusted from the December 31, 2014 exercise price of $3.02 to $2.05 per share pursuant to a formula provided in the original warrant agreement.

Derivative Instruments

On January 6, 2015, the Company settled outstanding NYMEX West Texas Intermediate oil derivative swap contracts on a total of 120,000 barrels of oil, resulting in a cash settlement received of $5,317,300, as indicated below:

Settlement Period	Oil (Bbls)		Settlement Price		Cover Price		Cash Settlement
January 1, 2015 – March 31, 2015		30,000		93.50		51.67		1,255,000
January 1, 2015 – March 31, 2015		36,000		96.05		51.67		1,597,800
January 1, 2015 – March 31, 2015		21,000		97.00		51.67		952,000
January 1, 2015 – March 31, 2015		33,000		97.50		51.67		1,512,500
Total		120,000	$	95.98	$	51.67	$	5,317,300

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OIL AND NATURAL GAS PROPERTIES (Tables)

12 Months Ended

Dec. 31, 2014

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Schedule of Purchase Price Allocation of Net Acreage Acquisition, McKenzie, Billings, Dunn and Williams Counties, North Dakota

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

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

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

Schedule of Pro Forma Operating Results of Net Acreage Acquisition, McKenzie, Billings, Dunn and Williams Counties, North Dakota

Pro Forma Operating Results

In accordance with ASC Topic 805, presented below are unaudited pro forma results for the year ended December 31, 2014 and 2013 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:

	Year Ended December 31,
	2014			2013
Revenues	$	126,418,589		$	57,151,128
Net Loss Available to Common Stockholders	$	(48,179,709	)	$	(29,179,483	)
Net Loss Per Share – Basic and Diluted	$	(0.72	)	$	(0.71	)
Weighted Average Shares Outstanding – Basic and Diluted		66,772,458			41,383,277

Schedule of Pro Forma Earnings Related to Net Acreage Acquisition, McKenzie, Billings, Dunn and Williams Counties, North Dakota

Post-Acquisition Operating Results

The amount of revenues and excess of revenues over direct operating expenses included in the accompanying Consolidated Statements of Operations for the September 2014 acquisition is shown in the table that follows. Direct operating expenses include lease operating expenses, selling, general and administrative expenses and production and other taxes.

	Year Ended December 31,
	2014		2013
Revenues	$	2,590,658	$	—
Excess of revenues over direct operating expenses	$	1,299,829	$	—

Schedule of Oil and Gas Property Net Sales Price Allocation for Sale of company Interst in Wolliston Basin Non-Operated Net Acres

Total capitalized costs within the full cost pool are allocated on the basis of the relative fair values of the properties sold and those retained due to substantial economic differences between the properties sold and those retained. Following this methodology, the following table represents a net sales price allocation of the transaction (in thousands):

Sale price	$	111,090
Add:  Disposition of asset retirement obligations		309
Less: Sale expenses		(1,168	)
Purchase price adjustments		(1,520	)
Sale price, net	$	108,711
Proved oil and natural gas properties	$	137,279
Accumulated depletion		(49,508	)
Unproved oil and natural gas properties		13,568
Gain on sale		7,372
Sale price, net	$	108,711

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PREFERRED AND COMMON STOCK (Summary of Restricted Stock Units and Restricted Shares Outstanding) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Non-vested restricted stock and restricted stock units
Number of Shares, Beginning	2,082,187	1,847,701
Number of Shares, Granted	264,134	1,242,505	1,919,135
Number of Shares, Canceled	(73,204)	(70,642)
Number of Shares, Forfeited	(639,299)	(302,016)	(53,577)
Number of Shares, Vested	(1,049,198)	(635,361)	(17,857)
Number of Shares, Ending	584,620	2,082,187	1,847,701
Weighted Average Grant Date Fair Value, Beginning	$ 5.73	$ 4.31
Weighted Average Grant Date Fair Value, Granted	$ 7.48	$ 7.10	$ 4.93
Weighted Average Grant Date Fair Value, Canceled	$ 7.23	$ 4.19
Weighted Average Grant Date Fair Value, Forfeited	$ 5.48	$ 4.86	$ 21.00
Weighted Average Grant Date Fair Value, Vested	$ 5.36	$ 4.88	$ 21.00
Weighted Average Grant Date Fair Value, Ending	$ 7.27	$ 5.73	$ 4.31

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OIL AND NATURAL GAS PROPERTIES (Narrative) (Details) (USD $)	0 Months Ended				1 Months Ended		0 Months Ended
	Sep. 02, 2014	Feb. 13, 2014	Jan. 02, 2014 Boe	Mar. 28, 2013	Feb. 28, 2014	Dec. 31, 2013	Feb. 21, 2014	Sep. 06, 2013 acre	Apr. 17, 2013 acre
Amount received from unrelated third party for acquiring land	$ 71,200,000	$ 69,200,000			$ 10,300,000	$ 2,000,000
Net daily production on acreage			300
Percentage of working interest in leaseholds				45.00%
Sale price of land							8,600,000
Purchase price adjustments to the buyer							2,400,000
Fair value of acreage related to sales price adjustments	35,918,000
Maximum [Member]
Percentage on sale of proved reserves of oil and natural gas							25.00%
Williams and McKenzie Counties [Member]
Number of acres in net acquired		19,500
McKenzie and Billings Counties [Member]
Number of acres in net acquired					5,900
McKenzie, Billings and Dunn Counties [Member]
Number of acres in net acquired	30,500
Williams County [Member]
Number of acres in net acquired	4,300
Routt and Moffatt Counties [Member]
Number of acres in net acquired				31,000
Sale price of land				10,100,000
Routt County [Member]
Number of acres in net acquired						14,600
Williston Basin [Member]
Number of acres in net acquired									970
Sale price of land								5,200,000	7,100,000
Non operated area of land								413
Williston Basin [Member] | Oil and Natural Gas Production [Member]
Sale price of land								111,000,000
Non operated area of land								26,579
Value of sale price remain in escrow account								$ 11,000,000

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CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss	$ (52,145,225)	$ (10,882,895)	$ (62,296,099)
Adjustments to Reconcile Net Loss to Net Cash Provided By (Used For) Operating Activities:
Depletion of Oil and Natural Gas Properties	34,798,218	17,310,059	12,770,718
Impairment of Oil and Natural Gas Properties	66,430,000	0	61,900,692
Depreciation and Amortization	389,551	144,492	53,818
Amortization of Debt Issuance Costs	1,711,171	127,857	1,929,561
Accretion of Discount on Asset Retirement Obligations	104,803	32,449	14,988
Net (Gains) Losses on Commodity Derivatives	(11,439,240)	2,656,535	215,439
Net Cash Settlements Paid on Commodity Derivatives	5,542,110	(1,984,778)	(34,191)
Gain on Sale of Oil and Natural Gas Properties		(7,371,804)
Gain on Acquisition of Business			(7,213,835)
Warrant Revaluation Expense (Gain)	(13,504,000)	7,077,000
Share-Based Compensation Expense	11,459,431	12,885,209	7,318,690
Debt Conversion Expense	10,438,080
Deferred Income Taxes
Changes in Assets and Liabilities
(Increase) Decrease in Trade Receivables - Oil and Natural Gas Revenues	1,512,366	(200,956)	(5,267,453)
Increase in Accounts Receivable - Joint Interest Partners	(319,260)	(27,464,913)	(4,058,291)
(Increase) Decrease in Other Receivables	(402,908)	556,440	(1,133,849)
Increase in Prepaid Expenses and Other Current Assets	(82,762)	(103,126)	(54,843)
Increase in Other Non-Current Assets	(73,201)	(96,869)	(100,100)
Increase in Accounts Payable	9,152,337	2,831,342	30,123
Increase (Decrease) in Accrued Expenses	(7,055,970)	8,412,533	214,399
Increase (Decrease) in Other Non-Current Liabilities	(56,327)	56,327
Increases in Advances from Joint Interest Partners	371,709	2,205,538
Net Cash Provided By Operating Activities	56,830,883	6,190,440	4,289,767
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of Other Property and Equipment	(1,692,561)	(505,788)	(172,785)
Restricted Cash Released	17,000,512
Restricted Cash Received		(21,000,512)
Payments of Restricted Cash	(2,648,721)
Increase in Deposits for Acquisitions	(14,805)	(125,368)
Use of (Payments for) Prepaid Drilling Costs		100,193	(67,030)
Proceeds from Sale of Oil and Natural Gas Properties, Net of Transaction Costs	36,155,859	129,432,743
Investment in Oil and Natural Gas Properties	(478,068,380)	(182,901,806)	(66,212,818)
Net Cash Used For Investing Activities	(429,268,096)	(75,000,538)	(66,452,633)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the Issuance of Convertible Notes, Net of Transactions Costs	166,893,211
Proceeds from Issuance of Common Stock, Net of Transaction Costs		238,354,687	72,167,012
Proceeds from Issuance of Preferred Stock, Net of Transaction Costs		47,183,994
Payments on Preferred Stock		(50,000,000)
Advances on Revolving Credit Facility and Term Loan	110,000,000		56,530,730
Payments on Revolving Credit Facility	(35,000,000)	(23,500,000)	(33,030,730)
Payments of Senior Secured Promissory Notes			(15,000,000)
Payment of Assumed Liabilities			(20,303,903)
Cash Paid for Finance Costs	(24,605)	(333,333)	(1,935,131)
Preferred Stock Dividends and Deemed Dividends		(8,832,191)
Cash Paid for Debt Issuance Costs	(1,408,351)
Proceeds from Exercise of Stock Options and Warrants	110,750
Net Cash Provided by Financing Activities	240,571,005	202,873,157	58,427,978
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(131,866,208)	134,063,059	(3,734,888)
CASH AND CASH EQUIVALENTS - BEGINNING OF PERIOD	144,255,438	10,192,379	13,927,267
CASH AND CASH EQUIVALENTS - END OF PERIOD	12,389,230	144,255,438	10,192,379
Supplemental Disclosure of Cash Flow Information
Cash Paid During the Period for Interest	2,121,184	255,776	1,154,943
Cash Paid During the Period for Income Taxes
Non-Cash Financing and Investing Activities:
Oil and Natural Gas Properties Included in Account Payable	107,957,324	60,141,180	38,973,137
Stock-Based Compensation Capitalized to Oil and Natural Gas Properties	2,273,656	1,193,960	582,040
Accretion on Preferred Stock Issuance Discount		8,626,000
Accretion of Preferred Stock Issuance Costs		2,816,000
Asset Retirement Obligation Costs and Liabilities	1,966,907	676,240	164,967
Asset Retirement Obligations Associated With Properties Sold	19,317	312,625
Asset Retirement Obligations Settled through P&A	72,556
Common Stock Issued for Oil and Natural Gas Properties		6,736,935
Debt Extinguished in Conversion of Convertible Notes	21,000,000
Purchases through Issuance of Common Stock or Assumption of Liabilities:
Oil and Natural Gas Properties			40,787,238
Other Property and Equipment			36,000
Other Non-Current Assets			75,000
Non-Cash Acquisition of Business Amounts:
Fair Market Value of Common Stock Issued			13,380,501
Debt Assumed			$ 20,303,903

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RELATED PARTY TRANSACTIONS

12 Months Ended

Dec. 31, 2014

Related Party Transactions [Abstract]

RELATED PARTY TRANSACTIONS

NOTE 5  RELATED PARTY TRANSACTIONS

In February 2013, the Company entered into a securities purchase agreement (the “Securities Purchase Agreement”) with affiliates of White Deer Energy L.P. (“White Deer Energy”), pursuant to which the Company issued to White Deer Energy 500,000 shares of Series A Perpetual Preferred Stock (“Series A Preferred Stock”), 5,114,633 shares of Series B Voting Preferred Stock (“Series B Preferred Stock”) and warrants to purchase an initial aggregate amount of 5,114,633 shares of the Company’s common stock at an initial exercise price of $5.77 per share, for an aggregate $50 million. Pursuant to the 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 Director 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 5,114,633 shares of Company common stock issuable upon exercise of the warrants and use commercially reasonable efforts to cause such registration statement to be declared effective within 120 days after the filing thereof. In June 2013 and October 2013, the Company amended the registration rights agreement to include 2,785,600 shares of Company common stock and 5,092,852 shares of Company common stock, respectively, issued to White Deer Energy in connection with subsequent private placements. On April 19, 2014, the Company received a request from White Deer Energy to register the shares of Company common stock and the shares of Company common stock underlying the warrants held by White Deer Energy.  On May 16, 2014, the Company filed with the SEC a registration statement on Form S-3 to register for resale the 7,878,452 shares of common stock and 5,114,633 shares of common stock underlying the warrants held by White Deer Energy, and the SEC declared the registration statement effective on May 30, 2014.

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STOCK OPTIONS AND WARRANTS (Schedule of the Status of Warrants Outstanding) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Feb. 08, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Warrants Outstanding (in Units)	223,293		223,293	223,293	223,293
Exercise Price, Warrants Outstanding (in Dollars per Unit)						$ 49.70
Warrants [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Warrants Outstanding (in Units)	6,230,784
Exercise Price, Warrants Outstanding (in Dollars per Unit)						$ 49.70
Warrants [Member] | December 1, 2009 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Warrants Outstanding (in Units)	37,216
Exercise Price, Warrants Outstanding (in Dollars per Unit)	$ 6.86
Expiration Date, Warrants Outstanding (in Date)	Dec. 01, 2019
Warrants [Member] | December 31, 2009 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Warrants Outstanding (in Units)	186,077
Exercise Price, Warrants Outstanding (in Dollars per Unit)	$ 6.86
Expiration Date, Warrants Outstanding (in Date)	Dec. 31, 2019
Warrants [Member] | February 8, 2011 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Warrants Outstanding (in Units)	892,858
Exercise Price, Warrants Outstanding (in Dollars per Unit)	$ 49.70
Expiration Date, Warrants Outstanding (in Date)	Feb. 08, 2016
Warrants [Member] | February 19, 2013 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Warrants Outstanding (in Units)	5,114,633	[1]
Exercise Price, Warrants Outstanding (in Dollars per Unit)	$ 3.02	[1]
Expiration Date, Warrants Outstanding (in Date)	Dec. 31, 2019	[1]

[1] See Note 16 - Subsequent Events for details on the warrant price adjustment subsequent to December 31, 2014.

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FAIR VALUE (Schedule of Fair Value of Financial Instruments Measured on Recurring Basis) (Details) (Fair Value, Measurements, Recurring [Member], USD $)	Dec. 31, 2014	Dec. 31, 2013
Fair Value Inputs Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total
Fair Value Inputs Level 1 [Member] | Warrant Liability - Long Term Asset (Liability) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total
Fair Value Inputs Level 1 [Member] | Commodity Derivatives - Current Liability (oil swaps) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total
Fair Value Inputs Level 1 [Member] | Commodity Derivatives - Long Term Asset (oil swaps) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total
Fair Value Inputs Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total	5,044,125	(853,005)
Fair Value Inputs Level 2 [Member] | Warrant Liability - Long Term Asset (Liability) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total
Fair Value Inputs Level 2 [Member] | Commodity Derivatives - Current Liability (oil swaps) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total	5,044,125	(921,401)
Fair Value Inputs Level 2 [Member] | Commodity Derivatives - Long Term Asset (oil swaps) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total		68,396
Fair Value Inputs Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total	(2,199,000)	(15,703,000)
Fair Value Inputs Level 3 [Member] | Warrant Liability - Long Term Asset (Liability) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total	(2,199,000)	(15,703,000)
Fair Value Inputs Level 3 [Member] | Commodity Derivatives - Current Liability (oil swaps) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total
Fair Value Inputs Level 3 [Member] | Commodity Derivatives - Long Term Asset (oil swaps) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total

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PREFERRED AND COMMON STOCK (Tables)

12 Months Ended

Dec. 31, 2014

Stockholders' Equity Note [Abstract]

Schedule of Components of Preferred Stock Transaction

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

	December 31, 2014		December 31, 2013		February 19, 2013 (issuance date)
Series A Preferred Stock	$	—	$	—	$	41,369,000
Series B Preferred Stock		5,000		5,000		5,000
Warrant Liability		2,199,000		15,703,000		8,626,000
Total	$	2,204,000	$	15,708,000	$	50,000,000

Schedule of Restricted Stock Units and Restricted Stock Shares Outstanding

A summary of the restricted stock units and restricted stock shares outstanding is as follows:

	Number of Shares			Weighted Average Grant Date Fair Value
Non-vested restricted stock and restricted stock units at January 1, 2012		—		$	—
Granted		1,919,135			4.93
Canceled		—			—
Forfeited		(53,577	)		21.00
Vested		(17,857	)		21.00
Non-vested restricted stock and restricted stock units at December 31, 2012		1,847,701			4.31
Granted		1,242,505			7.10
Canceled		(70,642	)		4.19
Forfeited		(302,016	)		4.86
Vested		(635,361	)		4.88
Non-vested restricted stock and restricted stock units at December 31, 2013		2,082,187			5.73
Granted		264,134			7.48
Canceled		(73,204	)		7.23
Forfeited		(639,299	)		5.48
Vested		(1,049,198	)		5.36
Non-vested restricted stock and restricted stock units at December 31, 2014		584,620		$	7.27

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DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT (Schedule of Derivative Instruments in Statement of Financial Position) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivative [Line Items]
Total	$ 5,044,125	$ (853,005)	$ (181,248)
Current assets [Member] | Swap Contracts [Member]
Derivative [Line Items]
Total	5,044,125
Non-current liabilities [Member] | Warrant Liability [Member]
Derivative [Line Items]
Total	(2,199,000)	(15,703,000)
Current liabilities [Member] | Swap Contracts [Member]
Derivative [Line Items]
Total		(921,401)
Non-current assets [Member] | Swap Contracts [Member]
Derivative [Line Items]
Total		$ 68,396

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BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES (Schedule of Revenue by Major Customers) (Details) (Credit Concentration Risk [Member], Production [Member])	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Customer A [Member]
Concentration Risk [Line Items]
Concentration risk percentage (in Percent)	59.00%	24.00%
Customer B [Member]
Concentration Risk [Line Items]
Concentration risk percentage (in Percent)	22.00%	12.00%
Two Customers [Member]
Concentration Risk [Line Items]
Concentration risk percentage (in Percent)	81.00%

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COMMITMENTS AND CONTINGENCIES

12 Months Ended

Dec. 31, 2014

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

NOTE 15 COMMITMENTS AND CONTINGENCIES

The Company conducts the majority of its operations in leased facilities, which are accounted for as operating leases. Generally, the leases provide that the Company pays a base rent plus all insurance, maintenance and all other costs and expenses associated with the use of the buildings. Additionally, on some leases the Company pays a portion or all of the property taxes on the premises.

Total rent expenses for leased facilities and other equipment rentals were approximately $362,873, $399,382 and $115,659 for the years ended December 31, 2014, 2013 and 2012, respectively.

At December 31, 2014, the minimum rental commitments under all non-cancelable operating leases with initial or remaining terms of more than one year are as follows:

	Payment due for the year ended December 31,
Contractual Obligations	Total		2015		2016		2017		2018		2019
Office Leases (1)	$	2,320,441	$	464,088	$	472,630	$	481,171	$	489,713	$	412,839

(1) The Denver, Colorado office lease commenced on December 15, 2012 and, as amended, has a term of 66 months, expiring in October 2019.

As is customary in the oil and natural gas industry, the Company may at times have commitments in place to reserve or earn certain acreage positions or wells. If the Company does not meet such commitments, the acreage positions or wells may be lost.

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