UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 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, 2013

or

o 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. — 001-35097

EMERALD OIL, INC.

(Exact Name of Registrant as Specified in Its Charter)

Montana	77-0639000
(State or Other Jurisdiction of	(I.R.S. Employer
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) 323-0008

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 o 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 o 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 o

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 o

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. o

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 o	Accelerated Filer x	Non-Accelerated Filer o	Smaller Reporting Company o
	(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o 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 Equities) was approximately $238 million.

As of March 12, 2014, the registrant had 66,283,464 shares of common stock issued and outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the proxy statement related to the registrant’s 2014 Annual Meeting of Shareholders, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2013, 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;

· restrictions imposed by our debt instruments and compliance with our 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; 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 operation 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, formerly Statement of Financial Accounting Standards No. 69 “Disclosures About Oil and Gas Producing Activities.

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	9
Item 1B.	Unresolved Staff Comments	15
Item 2.	Properties	15
Item 3.	Legal Proceedings	15
Item 4.	Mine Safety Disclosures	15
	Part II
Item 5.	Market For Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities	15
Item 6.	Selected Financial Data	17
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	18
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	25
Item 8.	Financial Statements and Supplementary Data	25
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	25
Item 9A.	Controls and Procedures	25
Item 9B.	Other Information	27
	Part III
Item 10.	Directors, Executive Officers and Corporate Governance	27
Item 11.	Executive Compensation	27
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters	27
Item 13.	Certain Relationships and Related Transactions, and Director Independence	27
Item 14.	Principal Accountant Fees and Services	27
	Part IV
Item 15.	Exhibits and Financial Statement Schedules	27
Signatures		30
Index to Financial Statements		F-1

i

EMERALD OIL, INC.

ANNUAL REPORT ON FORM 10-K

FOR FISCAL YEAR ENDED DECEMBER 31, 2013

PART I

Item 1.   Business

Overview

Emerald Oil, Inc., a Montana 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, 2013, their corresponding pre-tax PV-10 values and our total standardized measure of discounted future net cash flows as of December 31, 2013:

	Gross Wells		Net Wells		Net Remaining Oil (MBbls)		Net Remaining Gas (MMcf)		Total (MBoe) (1)		Pre-Tax PV-10 (2) (in thousands)
Proved Developed Producing
Bakken/Three Forks		26		11.65		3,438.0		3,460.9		4,014.9	$	130,979.9
Other Fields		21		14.27		444.8		893.9		593.8		13,605.1
Total Proved Developed		47		25.92		3,882.8		4,354.8		4,608.7		144,585.0
Proved Developed, Not Producing
Bakken/Three Forks		7		5.75		1,928.2		1,415.8		2,164.1		43,605.4
Total Proved Developed, Not Producing		7		5.75		1,928.2		1,415.8		2,164.1		43,605.4
Total Proved Developed Properties		54		31.67		5,811.0		5,770.6		6,772.8		188,190.4
Proved Undeveloped
Bakken/Three Forks		38		17.55		5,764.6		4,231.6		6,470.0		49,231.8
Total Proved Undeveloped		38		17.55		5,764.6		4,231.6		6,470.0		49,231.8
Total Proved Reserves		92		49.22		11,575.6		10,002.2		13,242.8		237,422.2
Discounted Future Income Taxes												(39,050.7	)
Standardized Measure of Discounted Future Net Cash Flows											$	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 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 2011, we have significantly increased our annual average daily oil and natural gas sales volumes from 269 Boe/d for the year ended December 31, 2011 to 1,688 Boe/d for the year ended December 31, 2013, as summarized in the following table.

	Year Ended December 31,
	2013		2012		2011
Sales Volume (Total)
Oil (Bbls)		580,797		320,147		95,517
Gas (Mcf)		211,608		129,648		14,962
Sales volumes (Boe)		616,065		341,755		98,011
Average Daily Sales
Oil (Bbls)		1,591		877		262
Gas (Mcf)		580		355		41
Sales volumes (Boe)		1,688		936		269
Average Sales Prices
Oil, Net of Settled Derivatives (Bbls)	$	87.16	$	85.05	$	86.86
Gas (Mcf)		6.48		6.68		8.66
Barrel of Oil Equivalent with Settled Derivatives (Boe)	$	84.40	$	82.21	$	85.97
Average Production Costs
Oil (Bbls)	$	14.38	$	8.26	$	7.51
Gas (Mcf)		0.81		0.65		0.65
Barrel of Oil Equivalent (Boe)	$	13.83	$	7.98	$	7.42

In 2013, we incurred total capital well costs of approximately $145.1 million. Our well expenditures in 2013 related to our operated wells totaled $132.0 million to drill 14.68 net wells and complete 10.58 net wells, compared to our budgeted expenditures of $127.2 million. Our expenditures related to non-operated wells were $13.1 million during the year to drill 1.69 net wells and complete 1.07 net wells, in which $5.5 million were associated with non-operated wells sold during the year. We exceeded our capital budget by $17.9 million primarily as a result of increased drilling due to realized drilling efficiencies in our operated development program and higher than expected capital deployment into our non-operated properties.

Our capital expenditures budget for 2014 is $307.0 million, of which $182.0 million is expected to fund the drilling of 18.2 net wells operating two to three drilling rigs, and $125.0 million to fund leasehold acquisitions, all in the Williston Basin of North Dakota and Montana. We expect to fund our 2014 capital program through existing cash on hand, our expected cash flows from operations, and borrowing capacity expected to be available under our revolving credit facility.

As of December 31, 2013, we had approximately 85,000 net acres in the Williston Basin, pro forma for closed and pending acquisitions. We operate approximately 64,000 net acres, or 75% of our total net acreage. We have identified approximately 465 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:

· 54,000 net acres in the Low Rider area of McKenzie County, North Dakota;

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

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

· 2,000 net acres in the Pronghorn area in Stark and Billings Counties, North Dakota in the core of the Pronghorn field; and

· 17,000 net acres in the Lewis & Clark area of McKenzie County, North Dakota south of the Low Rider area.

The following table provides production results by well for all Emerald-operated wells drilled and completed through March 12, 2014:

	Well Results (Boe/d)
	24 Hour		30 Day		90 Day		150 Day		240 Day
Pirate 1-2-11H		1,801		1,025		621		505		503
Caper 1-15-22H		2,063		994		678		528		—
Mongoose 1-8-5H		1,523		892		619		603		—
Slugger 1-16-21H		1,342		782		508		516		—
Talon 1-9-4H		1,311		818		570		524		—
Arsenal 1-17-20H		1,638		782		628		533		—
Hot Rod 1-27-26H		1,589		661		541		—		—
Hot Rod 4-27-26H		1,780		530		458		—		—
Excalibur 5-25-36H		1,842		702		514		—		—
Excalibur 3-25-36H		1,935		824		604		—		—
Pirate 5-2-11H		1,537		610		—		—		—
Pirate 6-2-11H		1,641		788		—		—		—
Caper 5-22-15H		1,515		704		—		—		—
Caper 6-22-15H		2,019		827		—		—		—
Excalibur 4-25-36H (Three Forks)		1,113		573		—		—		—
Caper 3-15-22H (Three Forks)		1,290		—		—		—		—
Caper 4-15-22H		1,711		—		—		—		—

Strategy

Our goal is to increase shareholder 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 capital expenditures in the Williston Basin. 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 85,000 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 75% 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.

· 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, 2013, we had no outstanding borrowings under our revolving credit facility. As of December 31, 2013, we had approximately $219.2 million of liquidity available, including approximately $144.2 million in unrestricted cash and short-term investments and $75.0 million available under our revolving credit facility. In February 2014, we acquired approximately 19,500 net acres and associated production for approximately $69.3 million, utilizing cash on hand and borrowing approximately $35.0 million under our revolving credit facility, which reduced our available liquidity to approximately $149.9 million, pro forma for the acquisition. We expect that our liquidity position, along with internally generated cash flows, will provide financial flexibility as we continue to develop and add to 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 85,000 net acres in the oil-producing core of the Williston Basin. We have identified an inventory of approximately 465 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, 2013, approximately 87% of our 13.2 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 75% 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 the Williston Basin.

2

· Our Size Allows Us to Evaluate a Broader Range of Acquisitions. Our size provides us with the opportunity to acquire smaller acreage blocks that may be less attractive to larger operators in the Williston Basin. We believe that our acquisition of smaller acreage blocks around our core operating areas should continue to facilitate our objective of expanding our acreage position in our core areas of the Williston Basin.

Area of Operation

Our Williston Basin acreage is located primarily in McKenzie and Williams 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. The Williston Basin also produces from many other formations including, but not limited to, the Mission Canyon, Nisku and Red River. We currently operate a two-rig drilling program and anticipate operating three drilling rigs for the majority of 2014. In addition to our operated program, we continue to selectively participate in non-operated interests drilled by other operators, but we do not actively seek non-operated acreage acquisitions.

Our operations are in an area that we believe has higher 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:

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 to some degree.

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, 2013, we had total proved reserves of approximately 13.2 MMBoe, all of which were located in the Williston Basin. Based on the results of our December 31, 2013 reserve report, our proved reserves increased approximately 147% during 2013 primarily as a result of increased drilling activity in our operated well program. We incurred approximately $145.1 million of capital expenditures for drilling activities and $56.4 million for acreage acquisitions during the year ended December 31, 2013, which directly contributed to the increase in our proved developed reserves. No other expenditures materially contributed to the development of proved developed reserves in 2013.

Our proved undeveloped reserves increased by approximately 90% during 2013 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, 2012 and 2013, approximately 2.2 MMBoe, or 67%, of proved undeveloped reserves were converted to proved developed reserves during 2013. The capital costs to develop these reserves were approximately $31.1 million. Also during 2013, we drilled wells at 22 locations and acquired 11 producing vertical locations that did not include proved reserves as of December 31, 2012. We sold approximately 5.1 MMBoe proved reserves in the divestiture of nearly all non-operated oil and natural gas assets on September 6, 2013. During 2013, we added 32 new proved undeveloped locations, which resulted in the addition of approximately 5.4 million Boe 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, 2013, our projected costs to develop our proved undeveloped reserves were $173.1 million in 2014 and $21.7 million in 2015. 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.

Summary of Proved Oil and Natural Gas Reserves

	As of December 31,
	2013 (2)		2012 (3)
Proved Developed Oil Reserves (MBbls)		5,811.0		1,788.2
Proved Undeveloped Oil Reserves (MBbls)		5,764.6		3,081.1
Total Proved Oil Reserves ((MBbls)		11,575.6		4,869.3
Proved Developed Gas Reserves (MMcf)		5,770.6		1,014.2
Proved Undeveloped Gas Reserves (MMcf)		4,231.6		1,894.3
Total Proved Gas Reserves (MMcf)		10,002.2		2,908.5
Total Proved Oil Equivalents (MBoe) (1)		13,242.8		5,354.1
Present Value of Estimated Future Net Revenues After Income Taxes, Discounted at 10% (4) (In thousands)	$	198,371.5	$	85,284.8

(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 2013 oil and natural gas reserves are based on the 12-month unweighted average first of 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.

(3) The values for the 2012 oil and natural gas reserves are based on the 12-month unweighted average first of month price January through December 31, 2012 crude oil price of $94.71 per Bbl (WTI price) and natural gas price of $2.76 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, 2012 was $85.75 per Bbl of oil and $5.13 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.

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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):

	For the Years Ended December 31,
	2013		2012		2011
Pre-tax present value of estimated future net revenues (Pre-tax PV-10)	$	237,422.2	$	87,819.4	$	59,625.0
Present value of future income tax discounted at 10%		39,050.7		2,534.6		—
Standardized measure of discounted future net cash flows	$	198,371.5	$	85,284.8	$	59,625.0

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 applied company wide, and are comprehensive in nature. 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:

• Chief Operating Officer, David Veltri: Mr. Veltri has over 31 years of oil and natural gas industry experience with a major oil company and several independent oil companies, where he has managed and provided engineering for all phases of upstream and mid-stream oil and natural gas operations, covering North Dakota, Wyoming, the Rocky Mountains, the southern U.S., Mid-Continent, Louisiana, Texas and various international locations. Most recently, Mr. Veltri served as an independent petroleum engineering consultant from October 2011 through November 2012. From August 2008 through September 2011, Mr. Veltri served as Vice President/General Manager of Baytex Energy USA Ltd., where he managed business unit operations, capital drilling programs, lease maintenance and producing properties in the Williston Basin in North Dakota. From September 2006 to July 2008, Mr. Veltri was Production Manager at El Paso Exploration and Production Company, where he managed producing oil and natural gas properties located in northern New Mexico. Mr. Veltri received a Bachelor of Science in Mining and Engineering from West Virginia University.

• Vice President of Exploration and Business Development, Karl Osterbuhr: Mr. Osterbuhr has over 20 years of experience oil and natural gas industry 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 of 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.

• Senior Reservoir Engineer, Charles Hager: Mr. Hager has over 24 years of oil and natural gas industry experience.  He began his career with Amoco in 1990 where he focused his early development within the Amoco Research Center focusing on hydraulic fracturing, pressure transient analysis, and reservoir engineering.  After leaving Amoco in 1998, Mr. Hager held reservoir engineering management positions within Enron Oil and Gas International and Tom Brown Inc.  From 2004 to 2013, he was consulting with NSI Technologies, Inc., which holds five patents for hydraulic fracturing simulation.  Mr. Hager has published numerous technical articles for the Society of Petroleum Engineers and from 2006 to 2009 was the Technical Editor for the Well Stimulation section of the Journal of Petroleum Technology.  Mr. Hager holds a Bachelor of Science in Petroleum Engineering from the University of Alabama.

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.

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 reserve 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 of 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 reserve 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.

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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, 2013, 2012 and 2011 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, 2013, 2012 and 2011. We had no wells targeting natural gas reservoirs as of December 31, 2013, 2012 and 2011. 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.

	December 31,
	2013				2012				2011
	Gross		Net		Gross		Net		Gross		Net
North Dakota Bakken and Three Forks – operated		15		10.58		—		—		—		—
North Dakota vertical production – operated (1)		11		7.58		—		—		—		—
North Dakota Bakken and Three Forks – non-operated		11		1.07		178		7.12		75		2.32
Montana Bakken and Three Forks – non-operated		—		—		27		2.55		7		0.67
Total		37		19.23		205		9.67		82		2.99

(1) Vertical producing wells relate to existing wells included within an acreage acquisition on August 2, 2013. Operatorship was transferred to us upon closing the acquisition. The wells are producing from the Birdbear, Duperow and Red River formations.

Wells Being Drilled or Awaiting Completion

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, 2013, 2012 and 2011.

	December 31,
	2013				2012				2011
	Gross		Net		Gross		Net		Gross		Net
North Dakota Bakken and Three Forks – operated		6		5.12		2		1.02		—		—
North Dakota vertical production – operated		—		—		—		—		—		—
North Dakota Bakken and Three Forks – non-operated		1		0.63		25		0.86		58		2.77
Montana Bakken and Three Forks – non-operated		—		—		1		0.09		5		0.19
Total		7		5.75		28		1.97		63		2.96

Exploratory Wells

As of December 31, 2013, we were participating in 7 gross (5.75 net) wells in the process of being drilled or completed. Of these wells, all are classified as PDNP properties. The wells in process that are not classified as PDNP properties as of December 31, 2013, 2012 and 2011 are deemed exploratory wells and included in the table below.

	December 31,
	2013				2012				2011
	Gross		Net		Gross		Net		Gross		Net
North Dakota Bakken and Three Forks – operated		—		—		2		1.02		—		—
North Dakota Vertical Production – operated		—		—		—		—		—		—
North Dakota Bakken and Three Forks – non-operated		—		—		19		0.76		30		1.78
Montana Bakken and Three Forks – non-operated		—		—		—		—		—		—
Total		—		—		21		1.78		30		1.78

We had no dry holes in development or exploratory wells that we owned a material working interest in the years for the years ended December 31, 2013, 2012 and 2011.

Leasehold

As of December 31, 2013, we owned an interest in approximately 64,472 net acres (98,439 gross acres) in the Williston Basin of North Dakota and Montana, which does not include approximately 20,800 net acres (27,174 gross acres) acquired subsequent to year end. 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, 2013:

	Undeveloped Acreage (1)				Developed Acreage (2)				Total Acreage
	Gross		Net		Gross		Net		Gross		Net
North Dakota (3)		59,895		46,627		17,814		9,139		77,709		55,766
Montana		20,129		7,773		601		933		20,730		8,706
Total		80,024		54,400		18,415		10,072		98,439		64,472

(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.

(3) The table does not include approximately 20,800 net acres (27,174 gross acres) in North Dakota that we acquired subsequent to year end. The acquisition included 12,976 net (15,867 gross) undeveloped acres and 7,798 net (11,307 gross) developed acres.

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.

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 during 2014, 2015, 2016 and the following years and have no options for renewal:

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	Expiring Acreage (1) (2)
Year Ending	Gross		Net
December 31, 2014		21,328		10,303
December 31, 2015		31,403		30,498
December 31, 2016		5,386		2,408
Thereafter		1,161		510
Total		59,278		43,719

(1)

The table above does not include the acquisition of 20,800 net (27,174 gross) acres in North Dakota subsequent to year end. Approximately 12,187 net (15,867 gross) are undeveloped, with 2,769 net acres expiring in 2014, 1,823 net acres expiring in 2015, 1,975 net acres expiring in 2016 and 967 net acres expiring in years thereafter. We do not believe lease expirations will materially affect this acreage acquisition.

(2)

The table above does not include 10,681 net (20,746 gross) acres with options for lease renewal.

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, 2013, we had sales to two purchasers that exceeded 10% of our total oil and natural gas revenue, whereby such purchasers purchased 24% and 12%, 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 other customers would be 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.

We currently use 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 80% 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 2013, we experienced differentials ranging from $5.00 per Bbl to $15.00 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.

During 2013, approximately 40% our oil and natural gas production came from production in which we participated on a heads-up basis alongside third-party interests in wells drilled and completed in spacing units that include our acreage. For these non-operated properties, our operating partners generally market and sell the oil and natural gas produced from wells in which we have an interest. Our operating partners coordinate the transportation of our oil production to the appropriate pipelines pursuant to arrangements that such partners negotiate and maintain with various parties purchasing the production. We understand that our partners generally sell our production to a variety of purchasers at prevailing market prices under separately negotiated short-term contracts. We sold substantially all of our non-operated oil and natural gas properties in the Williston Basin in September 2013.

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.

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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 and impose other requirements relating to the exploration and production of oil and natural gas. Such states may also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, and the regulation of 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 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, although RCRA classifies certain oil field wastes as “non-hazardous,” 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

Our operations are also subject to the federal Clean Water Act and analogous state laws. The Clean Water Act and similar state acts regulate other 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. Under the Clean Water Act, the EPA has adopted regulations concerning discharges of storm water runoff. This 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. These 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 air emissions permitting programs and the imposition of other requirements. In addition, 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 ESA, exploration and production operations, as well as actions by federal agencies, may not significantly impair or jeopardize the species or its habitat. ESA provides for criminal penalties for willful violations of ESA. Other statutes that provide protection to animal and plant species 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.

Hydraulic Fracturing Concerns

The practice of hydraulic fracturing has recently become the subject of significant focus among 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, 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. 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.

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 areas, 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. We will continue to monitor the impact the Subcommittee’s recommendations, and any resulting rule-making activities evolving at federal and state levels, could have on our exploration and development activities.

During 2012, 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) confirmation of a water management plan in place for handling fracturing fluids that flow back to the surface. On January 21, 2013, the BLM announced that it was withdrawing its proposed regulations and the BLM issued a new set of proposed regulations regarding hydraulic fracturing in May 2013.

During 2012, the EPA proposed new guidelines under the Safe Drinking Water Act 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.

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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 2014. In addition, the EPA’s recently issued proposed rules subjecting oil and natural gas operations to regulation under the New Source Performance Standards will be applicable to newly drilled and fractured wells as well as existing wells that are refractured.

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 in which 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.

Employees

We currently have 30 full time employees. Our Chief Executive Officer, McAndrew Rudisill, and our Chief Financial Officer, Paul Wiesner, 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.

Company Background and Office Locations

We were 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. Our executive offices are located at 1600 Broadway Avenue, Suite 1360, Denver, Colorado 80202. A satellite office is located at 2718 Montana Avenue, Suite 220, Billings, Montana 59101. We believe our current office space will be sufficient to meet our needs for the foreseeable future.

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, DC 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” our Audit Committee Charter, Compensation Committee Charter, Governance/Nominating Committee Charter and 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.

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.

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, 2013, we have identified approximately 465 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, and inclusive of pending acreage acquisitions. 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.

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 $5.00 to $15.00 less per Bbl than prices for other areas in the United States during 2013. 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.

At December 31, 2013, approximately 49% 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.

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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 completely 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.

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. 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 many of the areas 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.

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 2013 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.

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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 shareholders 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.

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.

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 $75.0 million as of December 31, 2013. 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. 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.

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Any additional capital raised through the sale of equity will dilute the ownership percentage of our shareholders. 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 $10,882,895, $62,296,099 and $1,345,054 for the fiscal years ended December 31, 2013, 2012 and 2011, 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.

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 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 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 bank 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 credit facility. A default, if not cured or waived, could result in all indebtedness outstanding under our 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.

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.

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 shareholders’ 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.

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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.

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.

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 (the “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 U.S. Environmental Protection Agency’s (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 2014 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 (the “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 (the “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. On October 21, 2011, the EPA announced its intention to propose federal Clean Water Act regulations by 2014 governing 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 is also considering whether to implement actions to lessen the environmental impact associated with hydraulic fracturing operations. Initiatives by the EPA and other federal and state regulators to expand their regulation of hydraulic fracturing, together with the possible adoption of new federal or state laws or regulations that significantly restrict hydraulic fracturing, could result in delays, eliminate certain drilling and injection activities, make it more difficult or costly for us to perform hydraulic fracturing, 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. 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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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.

Although 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, could significantly increase our operating, capital and compliance costs as well as delay or halt our ability to develop oil and natural gas reserves.

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 shareholders 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 shareholders.

As of March 12, 2014, White Deer Energy L.P. (“White Deer Energy”) beneficially owned approximately 18.2% of our outstanding common stock on a fully diluted basis, consisting of 7,878,452 shares of our common stock and a warrant 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. As a result, White Deer Energy is able to exercise significant influence over matters requiring shareholder 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 shareholders.

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.

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.

On April 17, 2012, the EPA approved final regulations under the U.S. Clean Air Act (the “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. For well completion operations occurring at such well sites before January 1, 2015, the final regulations allow operators to capture and direct flowback emissions to completion combustion devices, such as flares, in lieu of performing green completions. These regulations also establish specific new requirements regarding emissions from dehydrators, storage tanks and other production equipment. The EPA later updated the storage tank standards on August 5, 2013 to phase-in emission controls more gradually. We continue to review these requirements and assess their potential impacts. Compliance with these requirements could increase our costs of development and production, although we do not expect these requirements to be any more burdensome to us than to other similarly situated companies involved in oil and natural gas exploration and production activities.

The adoption of climate change legislation by Congress 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 paving 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.

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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.

We presently transport some of our oil production from the Bakken/Three Forks area to market by rail. 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 U.S. Department of Transportation 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. In addition, in February 2014, several rail carriers entered into a voluntary agreement with the U.S Department of Transportation (and some of its constituent agencies) to impose more stringent standards for shipments of oil.

We do not currently own or operate rail transportation facilities or rail cars; however, the adoption of any regulations that impact the 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.

The ongoing implementation of federal legislation enacted in 2010 could have an adverse impact on our ability to use derivative instruments to reduce the effects of commodity prices, interest rates, and other risks associated with our business.

Historically, we have entered into a number of commodity derivative contracts in order to hedge a portion of our oil and natural gas production. On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act which requires the SEC, and the Commodity Futures Trading Commission (or CFTC), along with other federal agencies, to promulgate regulations implementing the new legislation. The CFTC, in coordination with the SEC and various US federal banking regulators, has issued regulations to implement the so-called “Volcker Rule” under which banking entities are generally prohibited from proprietary trading of derivatives. Although conditional exemptions from this general prohibition are available, the Volcker Rule may limit the trading activities of banking entities that have been counterparties to our derivatives trades in the past. Also, a provision of the Dodd-Frank Act known as the “swaps push-out rule” may require some of the banking counterparties to our commodity derivative contracts to “push out” some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty.

The CFTC also has finalized other regulations implementing the Dodd-Frank Act’s provisions regarding on the “swap” and “swap dealer” definitions, swap dealer registration, swap data reporting, mandatory clearing, trade reporting, margin and position limits; however, some regulations remain to be finalized and it is not possible at this time to predict when the CFTC will adopt final rules. For example, the Dodd-Frank Act and the CFTC regulations may require compliance with margin requirements and with certain clearing and trade-execution requirements (or take steps to qualify for an exemption to such requirements) in connection with certain of our derivative activities. Also, the CFTC has re-proposed regulations setting position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions are expected to be made exempt from these limits.

It is possible that the CFTC, in conjunction with the US federal banking 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 negotiated credit thresholds above which we would be required to post collateral.

The Dodd-Frank Act and any additional implementing regulations could significantly increase the cost of some commodity derivative contracts (including through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of some commodity derivative contracts, limit our ability to trade some commodity derivatives to hedge risks, reduce the availability of some commodity derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing commodity derivative contracts and potentially increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a consequence, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Increased volatility may make us less attractive to certain types of investors. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. If the implementing regulations result in lower commodity prices, our revenues could be adversely affected. Any of these consequences could adversely affect our business, financial condition and results of operations.

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.”

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 and have been adjusted to reflect our 1-for-7 reverse stock split effected on October 23, 2012:

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Year Ended December 31, 2013
High	$	7.49	$	7.20	$	8.09	$	9.20
Low	$	5.17	$	5.81	$	6.36	$	6.54
Year Ended December 31, 2012
High	$	25.20	$	18.34	$	13.86	$	5.95
Low	$	17.01	$	11.20	$	5.46	$	3.90

Holders

As of March 12, 2014, we had 66,283,464 shares of our common stock outstanding, held by approximately 571 shareholders 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.

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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, 2013.

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		1,048,155	$	7.63		4,629,784
Equity Compensation Plans Not Approved by Security Holders (1)		333,998		11.51		—
Total		1,382,153	$	8.57		4,629,784

(1) On December 1, 2009, we issued our Vice President – Accounting warrants to purchase a total of 37,216 shares of common stock exercisable at $6.86 per share pursuant to the terms of his employment agreement. On December 31, 2009, we issued our Executive Chairman warrants to purchase a total of 186,077 shares of common stock exercisable at $6.86 per share pursuant to the terms of his employment agreement. 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 a newly appointed 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, 2013.

Issuer Purchases of Equity Securities

The following table summarizes repurchases of our common stock during the three months ended December 31, 2013.

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
10/1/2013 – 10/31/2013		—	$	—		—		—
11/1/2013 – 11/30/2013		—		—		—		—
12/1/2013 – 12/31/2013		302,016		7.40		—		—
Total		302,016	$	7.40		—		—

(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, 2013, 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, 2013.

Emerald Oil, Inc.
Total Return Performance

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

	4/16/2010		6/30/2010		12/31/2010		6/30/2011		12/30/2011		6/29/2012		12/31/2012		6/28/2013		12/31/2013
Emerald Oil, Inc.	$	100.00	$	271.43	$	385.71	$	212.14	$	183.57	$	125.71	$	53.47	$	70.00	$	78.16
Standard & Poor’s Composite 500 Index	$	100.00	$	86.46	$	105.50	$	110.78	$	105.49	$	114.26	$	119.63	$	134.74	$	155.05
Amex Oil Index	$	100.00	$	79.48	$	109.11	$	117.31	$	110.55	$	104.83	$	111.69	$	119.60	$	135.20

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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, 2013, 2012, 2011 and 2010, and the related statements of operations, stockholders’ equity, and cash flows for the years ended December 31, 2013, 2012, 2011 and 2010 beginning on page F-1 of this report. On April 16, 2010, our predecessor company, ante4, Inc. acquired Plains Energy Investments, Inc., at which time we began our present business operations.

	Year Ended December 31,
	2013			2012 (1)			2011			2010
Statements of Income Information:
Revenues
Oil and Natural Gas Sales	$	53,981,040		$	28,129,985		$	8,426,129		$	942,840
Net Losses on Commodity Derivatives		(2,656,535	)		(215,439	)		—			—
Total Revenues		51,324,505			27,914,546			8,426,129			942,840
Operating Expenses
Production Expenses		8,520,414			2,727,133			726,946			26,686
Production Taxes		5,702,521			2,955,015			717,440			102,743
General and Administrative Expenses		30,507,114			12,903,845			2,686,176			1,778,161
Depletion of Oil and Natural Gas Properties		17,310,059			12,770,718			3,546,466			547,844
Impairment of Oil and Natural Gas Properties		—			61,900,692			—			1,377,188
Depreciation and Amortization		144,492			53,818			30,831			2,929
Accretion of Discount on Asset Retirement Obligations		32,449			14,988			4,882			358
Gain on Sale of Oil and Natural Gas Properties		(7,371,804	)		—			—			—
Total Expenses		54,845,245			93,326,209			7,712,741			3,835,909
Income (Loss) from Operations		(3,520,740	)		(65,411,663	)		713,388			(2,893,069	)
Other Income (Expense), Net		(7,362,155	)		3,115,564			(2,058,442	)		(1,310,260	)
Loss Before Income Taxes		(10,882,895	)		(62,296,099	)		(1,345,054	)		(4,203,329	)
Income Tax Provision		—			—			—			65,240
Net Loss		(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	$	(31,162,092	)	$	(62,296,099	)	$	(1,345,054	)	$	(4,268,569	)
Net Loss Per Common Share – Basic and Diluted	$	(0.75	)	$	(4.91	)	$	(0.17	)	$	(0.79	)
Weighted Average Shares Outstanding – Basic and Diluted		41,383,277			12,699,544			8,012,158			5,434,084
Balance Sheet Information:
Total Assets	$	429,887,663		$	173,886,362		$	104,839,421		$	48,495,426
Long-term Liabilities	$	16,451,464		$	23,796,074		$	15,116,119		$	10,522
Total Liabilities	$	94,568,554		$	63,592,277		$	25,697,480		$	15,774,602
Stockholders’ Equity	$	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	$	6,190,440		$	4,289,767		$	(153,156	)	$	(1,165,634	)
Net cash used for investing activities	$	(75,000,538	)	$	(66,452,633	)	$	(43,508,278	)	$	(3,745,202	)
Net cash provided by financing activities	$	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 shareholder value through the development and acquisition of oil and natural gas assets that exhibit economically producible hydrocarbons.

As of December 31, 2013, we controlled the rights to mineral leases covering approximately 85,000 net acres, pro forma for closed and pending acquisitions. 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; and

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

Acquisitions and Divestitures

Acreage Acquisitions

In February 2014, we entered into a purchase and sale agreement with an unrelated third party to acquire approximately 5,900 net acres of undeveloped leasehold in McKenzie and Billings Counties of North Dakota for approximately $10.3 million. The acquisition adds one and two potentially operated DSUs in our Low Rider and Lewis & Clark Prospect Areas, respectively, and increases working interest in four existing DSUs. The purchase is expected to close on or before April 1, 2014.

On February 13, 2014, we acquired approximately 19,500 net acres located in Williams and McKenzie Counties, North Dakota from an unrelated third party for approximately $69.3 million in cash. Net daily production from the acreage was approximately 300 barrels of oil equivalent per day as of January 1, 2014, the effective date of the transaction. The acquisition adds 15 potentially operated DSUs in our Low Rider prospect and two potentially operated DSUs in our Lewis & Clark prospect. In connection with the acquisition we drew $35.0 million from our revolving credit facility with Wells Fargo on February 13, 2014.

On December 16, 2013 we acquired approximately 1,101 net acres located in Williams County, North Dakota from an unrelated third party for approximately $5.3 million in cash. The acquisition added two potentially operated DSUs in our Easy Rider prospect area.

On October 9, 2013, we acquired approximately 2,866 net acres of undeveloped leasehold in Williams County, North Dakota for approximately $3.2 million from an unrelated third party. The acquisition added seven potentially operated DSUs in our Low Rider and Easy Rider prospect areas. On September 20, 2013, we leased an additional 313 net acres of undeveloped lease hold in the same area in Williams County, North Dakota for approximately $1.3 million.

On September 17, 2013, we leased approximately 30,672 net undeveloped leasehold acres in McKenzie, Billings and Stark Counties, North Dakota, for approximately $20.2 million. The lease acquisitions added 38 potentially operated DSUs in our Low Rider, Easy Rider, Pronghorn Sand and Lewis & Clark prospect areas. In connection with the lease acquisitions, we agreed to drill at least five gross wells within the prospect area prior to September 17, 2015. We placed $10 million with an escrow agent, of which $2 million per well will be returned to us with each well drilled within the term of the escrow agreement.

On August 30, 2013, we acquired approximately 3,600 net acres of undeveloped leasehold in McKenzie County, North Dakota from an unrelated third party for approximately $3.6 million or approximately $1,000 per net acre. The acquired acreage is directly south and contiguous to our existing operated area in McKenzie County, North Dakota. The acquisition added six potentially operated DSUs in our Low Rider Prospect in McKenzie County, North Dakota.

On August 2, 2013, we acquired approximately 3,500 net acres of partially developed leasehold in McKenzie County, North Dakota, from an unrelated third party for approximately $10.4 million or approximately $3,000 per net acre. The acquired acreage is directly southeast and contiguous to our existing Low Rider prospect area in McKenzie County, North Dakota. The acquisition added eight potentially operated DSUs in our Low Rider area.

Non-Operated Acreage Sales

On September 6, 2013, we sold 26,579 non-operated net acres located in the Williston Basin and the associated oil and natural gas production for approximately $111.0 million in cash, subject to certain post-closing adjustments, which sale we refer to as the “Non-Operated Asset Sale.” Under the purchase agreement, the Non-Operated Asset Sale was given economic effect as of April 1, 2013 such that all proceeds and certain operational costs and expenses attributable to the properties sold were apportioned between the purchaser and us based on such date. On September 6, 2013, we also sold 413 non-operated net acres located in the Williston Basin for approximately $5.2 million in cash. In addition, we sold 970 non-operated net acres in the Williston Basin in April 2013 for approximately $7.1 million in cash. We used and intend to use the proceeds from these divestitures to fund a portion of our 2013 and 2014 capital budgets.

2014 Capital Development Plan

On July 26, 2012, we acquired Emerald Oil North America and made a strategic decision to focus on acquiring operated acreage in the Williston Basin and commence an operated drilling program to develop our leasehold position. The operated drilling program creates higher rate of return opportunities while allowing us to control the deployment of our capital development budget. We expect to fund our current 2014 capital expenditure budget using cash on hand, cash flow from operations and borrowings under our revolving credit facility. We may consider funding growth opportunities beyond our current 2014 capital expenditure budget with future capital markets activity if we believe the transaction to be accretive to shareholders.

Our future financial results will depend primarily on: (i) the ability to continue to source and evaluate potential projects; (ii) the ability to fully implement our exploration and development program, which is dependent on the availability of capital resources; (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.

For the year ended December 31, 2013, we planned to spend approximately $127.2 million to drill 12.0 net operated and 0.5 net non-operated wells in the Williston Basin. We incurred capital costs of approximately $145.1 million to drill 14.68 net operated wells, complete 10.58 net operated wells, drill 1.69 net non-operated wells and complete 1.07 net non-operated wells. We exceeded our capital budget by $17.9 million primarily as a result of increased drilling due to realized drilling efficiencies in our operated development program and higher than expected capital deployment into our non-operated properties. For the year ended December 31, 2013, we had a budget of approximately $20.0 million to increase our operated acreage position in our core operated area in McKenzie County, North Dakota. We incurred acreage acquisition costs of approximately $56.4 million, primarily in our Low Rider prospect area. We added a high specification drilling rig to accelerate development of our Williston Basin operated leasehold, which commenced drilling in June 2013. We expect to add a third horizontal-capable rig in the first half of 2014. For the 12-month period ending December 31, 2014, we plan to spend approximately $182.0 million to drill 18.2 net operated wells in the Williston Basin at an average cost per net well of approximately $10.0 million. We have budgeted approximately $125.0 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.

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The following table presents summary data for our Williston Basin project area for the years ended December 31, 2013 and 2014:

			Net Identified		Actual Capital Expenditures 2013 (1)				Planned Capital Expenditures 2014
	Net Acres		Drilling Locations		Net Wells		Drilling Capex (in millions)		Net Wells		Drilling Capex (in millions)
Low Rider		54,000		297		10.58	$	110.7		12.2	$	122.0
Easy Rider		4,000		22		—		—		2.0		20.0
Richland		8,000		44		—		—		2.0		20.0
Pronghorn		2,000		6		—		—		2.0		20.0
Lewis & Clark		17,000		66		—		—		—		—
Total		85,000		435		10.58	$	110.7		18.2	$	182.0

(1) Actual Capital Expenditure in 2013 includes drilling costs on net wells drilled and completed during 2013. It does not include 6 gross, 5.12 net operated wells in the process of drilling, completing or awaiting completion with $21.3 million of costs incurred as of December 31, 2013.

The Low Rider area, which is our core operated area, consists of approximately 54,000 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, 2013 was approximately 75%, and we continue to work toward increasing our average working interest in the area. As of December 31, 2013, we had approximately 15 gross (10.58 net) producing operated wells in the Williston Basin. As of December 31, 2013, we were running a two-rig horizontal development program in the Low Rider area. Since we began operations in the Low Rider area in November 2012, we have drilled 21 horizontal wells, of which 15 are producing and six are drilling, completing or awaiting completion. 

Through June 30, 2013 the majority of our oil and natural gas production was derived from participation in wells in the Williston Basin as a non-operating partner, primarily on a heads-up, or pro rata, basis proportionate to our working interest with established operators. With the sale of substantially all of our non-operated oil and natural gas properties in the Williston Basin in September 2013 (see Acquisitions and Divestitures – Non-Operated Acreage Sales, above) our capital is being focused on developing our core operated areas.

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 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, 2013:

Current assets	$	200,278,683
Current liabilities		78,117,090
Working capital	$	122,161,593

Public Offerings and Private Placements

On May 22, 2013, we 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 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 $10.5 million.

On June 4, 2013, we completed a private placement of 2,785,600 shares of common stock at a price of $5.87 per share for total net proceeds of approximately $16.2 million. 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, we 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 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.

On October 17, 2013, we 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 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. 

We have used and intend to further use the net proceeds from these offerings, along with cash on hand, cash flow from operations, proceeds from the sale of assets and additional borrowings under our revolving credit facility, to fund our capital budget in 2013 and 2014. Any remaining net proceeds will be used for general corporate purposes, including working capital.

Series A Preferred Stock Transaction

During the first quarter of 2013, we completed a private offering with White Deer Energy pursuant to a securities purchase agreement (“Securities Purchase Agreement”), pursuant to which, in exchange for a cash investment of $50 million, we issued the following to White Deer Energy:

· 500,000 shares of Series A Perpetual Preferred Stock, $0.001 par value per share (the “Series A Preferred Stock”);

· 5,114,633 shares of Series B Voting Preferred Stock, $0.001 par value per share (the “Series B Preferred Stock”); and

· warrants to purchase an initial aggregate 5,114,633 shares of our common stock, $0.001 par value per share, at an initial exercise price of $5.77 per share. These warrants are exercisable until December 31, 2019.

The Series A Preferred Stock accumulated dividends at 10% per annum, which required us to make quarterly payments in either (i) cash or (ii) until April 1, 2015 and subject to obtaining prior shareholder approval to issue such shares and warrants, by issuance of (A) additional shares of Series A Preferred Stock valued at the same value as the initial per share purchase price of the Series A Preferred Stock and (B) an additional warrant to purchase shares of common stock. On July 10, 2013, our shareholders authorized us to issue at our option additional warrants and shares of common stock issuable upon exercise of such additional warrants as dividends on the Series A Preferred Stock until April 2, 2015.

On June 20, 2013, we redeemed 150,000 shares of the Series A Preferred Stock for $17,203,767 including $1,875,000 of redemption premium and $328,767 in accrued dividends on the redeemed shares. On August 30, 2013, we redeemed 200,000 shares of the Series A Preferred Stock for $22,828,767 including $2,250,000 of redemption premium and $328,767 of accrued dividends on the redeemed shares. On October 15, 2013, we redeemed the remaining 150,000 shares of the Series A Preferred Stock for $16,932,534 including $1,875,000 of redemption premium and $57,534 in accrued dividends on the redeemed shares. For each redemption, the redemption premium was treated as a dividend and recorded as a return of equity to the investor through a charge to additional paid-in capital.

For the year ended December 31, 2013, we paid cash dividends on the Series A Preferred Stock of $2,582,192. No dividends were paid prior to 2013.

Credit Facility

On November 20, 2012, we entered into a credit agreement (the “Credit Agreement”) with Wells Fargo Bank, N.A. (“Wells Fargo”), as administrative agent, and the lenders party thereto. The Credit Agreement is a senior secured reserve-based revolving credit facility with a maximum commitment of $400 million and had an initial borrowing base of $27.5 million (the “Wells Fargo Facility”). As of December 31, 2013, the Wells Fargo Facility was undrawn and the borrowing base was $75.0 million.

Amounts borrowed under the Wells Fargo Facility will mature on November 20, 2017, and upon such date, any amounts outstanding under the Wells Fargo Facility are due and payable. Redeterminations of the borrowing base are made on a semi-annual basis, with an option to elect an additional redetermination every six months between the semi-annual redeterminations.

The annual interest cost, which is dependent upon the percentage of the borrowing base utilized, is, at our option, based on either the Alternate Base Rate (as defined in the Credit Agreement) plus 0.75% to 1.75% or the London Interbank Offer Rate (LIBOR) plus 1.75% to 2.75%; provided, in no event may the interest exceed the maximum interest rate allowed by any current or future law. Interest on ABR Loans is due and payable on a quarterly basis, and interest on Eurodollar Loans is due and payable, at the our option, at one-, two-, three-, six- (or in some cases nine- or twelve-) month intervals. We will 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, 2013, the annual interest rate on the Wells Fargo Facility was 0.375%, which is the minimum commitment fee as no funds were drawn against the Wells Fargo Facility.

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A portion of the Wells Fargo Facility not in excess of $5 million will be available for the issuance of letters of credit by Wells Fargo. We will pay a rate per annum ranging from 1.75% to 2.75% on the face amount of each letter of credit issued and will pay a fronting fee equal to the greater of $500 and 0.125% of the face amount of each letter of credit issued. As of December 31, 2013, we have not obtained any letters of credit under the Wells Fargo Facility.

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

The Credit Agreement 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 Agreement 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 debt to EBITDA for the preceding four fiscal quarters of no more than 3.50 to 1.00, and (c) a fixed charge coverage ratio for any four fiscal quarters of at least 3.00 to 1.00. We were in compliance with all covenants as of December 31, 2013.

The principal balance amount on the Credit Agreement was $0 and approximately $23.5 million at December 31, 2013 and December 31, 2012, respectively. In connection with an acquisition we closed on February 13, 2014 (see Acquisitions and Divestitures – Acreage Acquisitions, above), we drew $35.0 million on the Wells Fargo Facility.

Satisfaction of Our Cash Obligations for the Next Twelve Months

We project we will have sufficient capital to accomplish our development plan and forecasted general and administrative expenses for the next twelve months. Our projections are based on cash on hand, the equity offerings completed in October 2013, increasing cash flow from operations, and expected increased borrowing capacity based on reserve growth. However, we may scale back our development plan should our projections of cash flow and borrowing capacity fall short of expectations or commodity prices fall substantially. We may also choose to access the equity or debt capital markets to fund acreage acquisitions and/or accelerated drilling at the discretion of management, depending on prevailing market conditions. We will evaluate any potential opportunities for acquisitions as they arise and meet our strategic objectives. Given our asset base and anticipated increasing cash flows, we believe we are in a position to take advantage of any appropriately priced acquisition opportunities that may arise. 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, expenses and difficulties frequently encountered by companies in their early stage of operations, particularly companies in the oil and natural gas exploration industry. Such risks include, but are not limited to, an evolving 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 revolving 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 use 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, 2013 were $144,255,438, compared to $10,192,379 as of December 31, 2012. The increase in our cash balance was primarily attributable to the public offerings completed on May 22, 2013 and October 2, 2013, the private placements completed on June 4, 2013 and October 17, 2013, the preferred stock and warrants issuance to White Deer Energy completed during the first quarter of 2013 and the sale of substantially all of our non-operated Williston Basin properties on September 6, 2013, offset by acquisitions and development of oil and natural gas properties, principal payments made under the Wells Fargo Facility and redemption of the Series A Preferred Stock.

Net Cash Provided By Operating Activities

Net cash provided by operating activities was $6,190,440 for the year ended December 31, 2013 compared to $4,289,767 for the year ended December 31, 2012. The change in the net cash provided by operating activities is primarily attributable to higher production revenue during 2013, offset by higher general and administrative expenses, including employment and employment-related expenses.

Net Cash Used For Investment Activities

Net cash used in investment activities was $75,000,538 for the year ended December 31, 2013 compared to $66,452,633 for the year ended December 31, 2012. 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 non-operated oil and natural gas properties of approximately $129.4 million.

Net Cash Provided By Financing Activities

Net cash provided by financing activities was $202,873,157 for the year ended December 31, 2013 compared to $58,427,978 for the year ended December 31, 2012. The change in net cash provided by financing activities for the year ended December 31, 2013 is primarily attributable to proceeds from the public offerings completed on May 22, 2013 and October 2, 2013, proceeds from the private placements completed on June 4, 2013 and October 19, 2013 and proceeds from the preferred stock and warrants issuance completed on February 19, 2013, offset by repayment of borrowings under the Wells Fargo Facility and payment of dividends on the Series A Preferred Stock and deemed dividends. Deemed dividends include the $6,250,000 premium paid on the Series A Preferred Stock redemption for the year ended December 31, 2013. The change in net cash provided by financing activities for the year ended December 31, 2012 is primarily attributable to proceeds from the public offering completed on September 28, 2012 and proceeds from our revolving credit facility completed in February 2012, offset by repayment of senior secured promissory notes.

Contractual Obligations and Commitments

As of December 31, 2013, we had no funds drawn on our $75 million revolving 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 and Billings, Montana office leases that expire on August 31, 2016, and April 1, 2014, respectively. The following table illustrates our contractual obligations as of December 31, 2013.

	Payment due by period
Contractual Obligations	Total		Less than 1 year		2 – 3 years		4 – 5 years		More than 5 years
Office Leases (1)	$	714,260	$	261,469	$	452,791	$	—	$	—
Automobile Leases (2)		14,848		11,879		2,970		—		—
Office Equipment (3)		73,000		24,000		48,000		1,000		—
	$	802,108	$	297,348	$	503,761	$	1,000	$	—

(1)	Our Denver, Colorado office lease commenced on December 15, 2012 and had a term of 26 months. In May 2013, the lease was amended following an expansion to the space. The amendment has a term of 40 months, expiring in August 2016. Our Billings, Montana office commenced on April 1, 2011 and has a term of 36 months, expiring in April 2014.
(2)	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.

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 (3) In October 2013 and December 2013, we entered into various leases for office equipment utilized by the Denver, Colorado and Billings, Montana offices, which expire in December 2016 and February 2017, respectively.

The above contractual obligations schedule does not include future 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, 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.

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.

	Year Ended December 31,
	2013			2012			2011
Net Oil and Natural Gas Revenues:
Oil	$	52,609,790		$	27,264,526		$	8,296,607
Natural Gas and Other Liquids		1,371,250			865,459			129,522
Total Oil and Natural Gas Sales		53,981,040			28,129,985			8,426,129
Net Losses on Commodity Derivatives		(2,656,535	)		(215,439	)		—
Total Revenues	$	51,324,505		$	27,914,546		$	8,426,129
Oil Derivative Net Cash Settlements Paid	$	1,984,778		$	34,191		$	—
Net Production:
Oil (Bbl)		580,797			320,147			95,517
Natural Gas and Other Liquids (Mcf)		211,608			129,648			14,962
Barrel of Oil Equivalent (Boe)		616,065			341,755			98,011
Average Sales Prices:
Oil (per Bbl)	$	90.58		$	85.16		$	86.86
Effect of Settled Oil Derivatives on Average Price (per Bbl)		(3.42	)		(0.11	)		—
Oil Net of Settled Derivatives (per Bbl)	$	87.16		$	85.05		$	86.86
Natural Gas and Other Liquids (per Mcf)	$	6.48		$	6.68		$	8.66
Barrel of Oil Equivalent with Net Cash Settlements Paid on Commodity Derivatives (per Boe)	$	84.40		$	82.21		$	85.97

Production costs incurred, presented on a per Boe basis, for the years ended December 31, 2013, 2012 and 2011 are summarized in the following table:

	Year Ended December 31,
	2013		2012		2011
Costs and Expenses Per Boe of Production :
Production Expenses	$	13.83	$	7.98	$	7.42
Production Taxes		9.26		8.65		7.32
G&A Expenses (Excluding Share-Based Compensation)		28.60		16.34		19.97
Shared-Based Compensation		20.92		21.42		7.43
Depletion of Oil and Natural Gas Properties		28.10		37.37		36.18
Impairment of Oil and Natural Gas Properties		—		181.13		—
Depreciation and Amortization		0.23		0.16		0.31
Accretion of Discount on Asset Retirement Obligation		0.05		0.04		0.05

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.

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.

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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.

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 revolving 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.

Year Ended December 31, 2012 Compared to the Year Ended December 31, 2011

Revenues

Revenues from sales of oil and natural gas were $28.1 million in 2012 compared to $8.4 million in 2011. For 2012, our total production volumes on a Boe basis increased 249% as compared to 2011. Production primarily increased due to the addition of 6.68 net productive wells in the Williston Basin. During 2012, we realized an $85.05 average price per Bbl of oil (including settled derivatives) compared to an $86.86 average price per Bbl of oil during 2011.

Net Losses on Commodity Derivatives

Net losses on commodity derivative loss were $215,439 for the year ended December 31, 2012. Net cash settlements paid on commodity derivatives were $34,191 for the year ended December 31, 2012. We did not have any commodity derivative contracts prior to January 1, 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, 2012, all of our derivative contracts were recorded at their fair value, which was a net liability of $181,248.

Production Expenses

Production expenses were $2,727,133 in 2012 compared to $726,946 in 2011. We experience increases in operating expenses as we add new wells and maintain production from existing properties. On a per unit basis, production expenses per Boe increased from $7.42 in 2011 to $7.98 in 2012. These increases are related to higher operating costs primarily in our Williston Basin wells. The largest cost driver in our Williston Basin wells during 2012 was the disposal of water.

Production Taxes

Production taxes were $2,955,015 in 2012 compared to $717,440 in 2011. We pay production taxes based on realized oil and natural gas sales. Our production tax rates were 10.5% in 2012 compared to 8.5% in 2011. 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 2012 average production tax rate was higher than 2011 due to expirations of production tax holidays during the year.

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General and Administrative Expense

General and administrative expenses were $12,903,845 in 2012 compared to $2,686,176 in 2011. The increase of $10,217,669 was 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, 2012 expense increased on a year-over-year basis compared to 2011 due to an increase of $8,812,951 related to increase in employee compensation and related expense and an increase of $993,925 related to professional and legal expense. Share-based compensation expenses are included in the employee compensation and related expenses, totaling $7,318,690 in 2012 compared to $728,546 in 2011.

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 $12,770,718 in 2012 compared to $3,546,466 in 2011. On a per-unit basis, depletion expense was $37.37 per Boe in 2012 compared to $36.18 per Boe in 2011. 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 2012 was due primarily to the addition of 6.68 net productive wells in the Williston Basin in 2012.

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.

We recognized an impairment expense at June 30, 2012 of $10,191,234 and at December 31, 2012 of $51,709,458 for a year ended December 31, 2012 total of $61,900,692. Included in the full cost pool at December 31, 2012 were $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 and $3.6 million of expiring leases in North Dakota we deemed uneconomic to pursue.  Combined, these items added $38.9 million of costs to the full cost pool without contributing reserves and discounted future net revenues to increase the ceiling.  The remaining $23.0 million impairment charge was a result of reclassifying proven undeveloped reserves into probable reserves.

Other Income (Expense), Net

Other income (expense), net was $(2,642,484) in 2012 compared to $(2,058,442) in 2011. Interest expense, the largest component of other income (expense) was $(2,614,240) in 2012 compared to $(2,036,032) in 2011. We capitalized $362,688 of interest costs during the year ended December 31, 2012. No interest was capitalized during the years ended December 31, 2011. 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 businesses during the year ended December 31, 2011.

Net Loss

We had net loss of $62,296,099 in 2012 compared to $1,345,054 in 2011 (representing $4.91 and $0.17 per share, respectively). The increase in net loss in our period-over-period results was driven by the $61,900,692 impairment of oil and natural gas properties in 2012 and increased expenses related to our strategic change and increase in infrastructure, offset by increased revenue and production from our oil and natural gas properties.

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,
	2013			2012			2011
Net loss	$	(10,882,895	)	$	(62,296,099	)	$	(1,345,054	)
Less: Preferred stock dividends and deemed dividends		(20,279,197	)		—			—
Net loss attributable to common stockholders		(31,162,092	)		(62,296,099	)		(1,345,054	)
Add:   Impairment of oil and natural gas properties		—			61,900,692			—
Interest expense		287,934			2,614,240			2,036,032
Accretion of discount on asset retirement  obligations		32,449			14,988			4,882
Depletion, depreciation and amortization		17,454,551			12,824,536			3,577,297
Stock-based compensation		12,885,236			7,318,690			728,546
Warrant revaluation expense		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			—			—
Net losses on commodity derivatives		2,656,535			215,439			—
Less:  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 paid on commodity derivatives		(1,984,778	)		(34,191	)		—
Adjusted EBITDA	$	20,154,228		$	16,800,247		$	5,001,703

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 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.

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.

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.

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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, 2012, 2011 and 2010 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. If oil prices decline by $1.00 per Bbl, then the standardized measure of our proved reserves as of December 31, 2013 would decline from $198.4 million to $192.8 million, or 2.8%. If natural gas prices decline by $0.10 per Mcf, then the standardized measure of our proved reserves as of December 31, 2013 would decline from $198.4 million to $193.4 million, or 2.5%. However, larger decreases in oil and natural gas prices may have a proportionately greater impact on our standardized measure.

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 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, 2013 published commodity futures price curves for crude oil, a hypothetical price increase or decrease of $1.00 per Bbl for crude oil would increase or decrease the fair value of our net commodity derivative liability by approximately $295,000. 

Interest Rate Risk

As of December 31, 2013, we had no outstanding borrowings under our credit facility. Our credit facility subjects us to interest rate risk on borrowings. This revolving credit facility allows us to fix the interest rate of borrowings under it for all or a portion of the principal balance for a period up to six months. To the extent the interest rate is fixed, interest rate changes affect the instrument’s fair market value but do not impact results of operations or cash flows. Conversely, for the portion of our borrowings that has a floating interest rate, interest rate changes will not affect the fair market value but will impact future results of operations and cash flows.

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, 2013, 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, 2013.

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.

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, 2013. 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 (1992).” Based on this assessment, management believes that, as of December 31, 2013, 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, 2013 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, formerly Voyager Oil & Gas, Inc., internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control – Integrated Framework (1992) 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, 2013, 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, 2013 and 2012, and the related statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2013 and our report dated March 12, 2014 expressed an unqualified opinion thereon.

/s/ BDO USA, LLP

Houston, Texas

March 12, 2014

26

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, 2013.

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, 2013.

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, 2013.

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, 2013.

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, 2013.

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.

27

Exhibit Index

Exhibit No.	Description of Exhibit
2.1	Letter Agreement, dated as of January 7, 2013, by and between Emerald Oil, Inc. and East Management Services, LP (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on January 8, 2013, and incorporated herein by reference).
2.2	Purchase and Sale Agreement, dated September 6, 2013, by and among Emerald Oil, Inc., Emerald WB LLC, and USG Properties Bakken II, LLC (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on September 12, 2013, and incorporated herein by reference).
3.1	Articles of Incorporation of Voyager Oil & Gas 1, Inc. (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on June 2, 2011, and incorporated herein by reference).
3.2	Articles of Merger of Voyager Oil & Gas, Inc. with and into Voyager Oil & Gas 1, Inc. dated as of May 31, 2011 (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on June 2, 2011, and incorporated herein by reference).
3.3	Articles of Amendment to the Articles of Incorporation of Voyager Oil & Gas, Inc. (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on October 24, 2012, and incorporated herein by reference).
3.4	Articles of Amendment to the Articles of Incorporation of Emerald Oil, Inc. (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on February 19, 2013, and incorporated herein by reference).
3.5	Amended Bylaws of Emerald Oil, Inc. (filed as Exhibit 3.2 to the Company’s Quarterly Report on Form 10-Q filed on November 8, 2012, and incorporated herein by reference).
4.1	Specimen Certificate of Common Stock of Emerald Oil, Inc. (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on October 24, 2012, 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).
**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).
**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	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).
10.12	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).
10.13	Borrowing Base Letter Agreement, dated as of August 9, 2013, by and between Emerald Oil, Inc. and Wells Fargo, National Association, as administrative agent for the lenders party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on August 13, 2013, and incorporated herein by reference).
10.14	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).
10.15	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).

28

Exhibit No.	Description of Exhibit
10.16	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).
10.17	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).
10.18	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).
10.19	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).
10.20	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).
*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.
*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.

29

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 12, 2014	By:
		/s/ MCANDREW RUDISILL
		McAndrew Rudisill
		Chief Executive Officer

POWER OF ATTORNEY

Each person whose signature appears below constitutes and appoints, McAndrew Rudisill and Paul Wiesner, 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	Director; Chief Executive Officer	March 12, 2014
McAndrew Rudisill	(principal executive officer)
/s/ PAUL WIESNER	Chief Financial Officer	March 12, 2014
Paul Wiesner	(principal financial officer and principal accounting officer)
/s/ JAMES RUSSELL (J.R.) REGER	Director; Executive Chairman	March 12, 2014
James Russell (J.R.) Reger
/s/ THOMAS J. EDELMAN	Director	March 12, 2014
Thomas J. Edelman
/s/ DUKE R. LIGON	Director	March 12, 2014
Duke R. Ligon
/s/ DANIEL L. SPEARS	Director	March 12, 2014
Daniel L. Spears
/s/ SETH SETRAKIAN	Director	March 12, 2014
Seth Setrakian

30

EMERALD OIL, INC.

(FORMERLY VOYAGER OIL & GAS, INC.)

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets as of December 31, 2013 and 2012	F-3
Consolidated Statements of Operations for the Years Ended December 31, 2013, 2012 and 2011	F-4
Consolidated Statements of Cash Flows for the Years Ended December 31, 2013, 2012 and 2011	F-5
Consolidated Statements of Stockholders’ Equity  for the Years Ended December 31, 2013, 2012 and 2011	F-6
Notes to the Consolidated Financial Statements	F-7

31

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., formerly Voyager Oil & Gas, Inc., as of December 31, 2013 and 2012 and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2013. 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, 2013 and 2012, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2013, 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, 2013, based on criteria established in Internal Control – Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 12, 2014 expressed an unqualified opinion thereon.

/s/ BDO USA, LLP

Houston, Texas

March 12, 2014

F-2

EMERALD OIL, INC.

CONSOLIDATED BALANCE SHEETS

AS OF DECEMBER 31,

	2013			2012
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	144,255,438		$	10,192,379
Restricted Cash		15,000,512			—
Accounts Receivable – Oil and Natural Gas Sales		8,715,821			8,514,865
Accounts Receivable – Joint Interest Partners		31,523,204			4,058,291
Other Receivables		577,409			1,133,849
Prepaid Expenses and Other Current Assets		206,299			103,173
Total Current Assets		200,278,683			24,002,557
PROPERTY AND EQUIPMENT
Oil and Natural Gas Properties, Full Cost Method, at cost:
Proved Oil and Natural Gas Properties		211,015,067			167,618,422
Unproved Oil and Natural Gas Properties		57,015,315			61,454,831
Equipment and Facilities		1,837,744			—
Other Property and Equipment		890,811			385,023
Total Property and Equipment		270,758,937			229,458,276
Less – Accumulated Depreciation, Depletion and Amortization		(48,176,522	)		(80,230,517	)
Total Property and Equipment, Net		222,582,415			149,227,759
Restricted Cash		6,000,000			—
Prepaid Drilling Costs		—			100,193
Fair Value of Commodity Derivatives		68,396			25,397
Debt Issuance Costs, Net of Amortization		475,157			269,681
Deposits on Acquisitions		125,368			—
Other Non-Current Assets		357,644			260,775
Total Assets	$	429,887,663		$	173,886,362
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts Payable	$	63,168,422		$	39,169,037
Fair Value of Commodity Derivatives		921,401			206,645
Accrued Expenses		11,821,729			420,521
Advances from Joint Interest Partners		2,205,538			—
Total Current Liabilities		78,117,090			39,796,203
LONG-TERM LIABILITIES
Revolving Credit Facility		—			23,500,000
Asset Retirement Obligations		692,137			296,074
Warrant Liability		15,703,000			—
Other Non-Current Liabilities		56,327			—
Total Liabilities		94,568,554			63,592,277
COMMITMENTS AND CONTINGENCIES
Preferred Stock – Par Value $.001; 20,000,000 Shares Authorized;
Series B Voting Preferred Stock – 5,114,633 and 0 issued and outstanding at December 31, 2013 and December 31, 2012, respectively.  Liquidation preference value of $5,115 and $0, as of December 31, 2013 and December 31, 2012, respectively.		5,000			—
STOCKHOLDERS’ EQUITY
Common Stock, Par Value $.001; 500,000,000 Shares Authorized, 65,840,370 and 24,734,643 Shares Issued and Outstanding, respectively		65,840			24,735
Additional Paid-In Capital		416,301,344			180,439,530
Accumulated Deficit		(81,053,075	)		(70,170,180	)
Total Stockholders’ Equity		335,314,109			110,294,085
Total Liabilities and Stockholders’ Equity	$	429,887,663		$	173,886,362

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

F-3

EMERALD OIL, INC.

(FORMERLY VOYAGER OIL & GAS, INC.)

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2013			2012			2011
REVENUES
Oil and Natural Gas Sales	$	53,981,040		$	28,129,985		$	8,426,129
Net Losses on Commodity Derivatives		(2,656,535	)		(215,439	)		—
Total Revenues		51,324,505			27,914,546			8,426,129
OPERATING EXPENSES
Production Expenses		8,520,414			2,727,133			726,946
Production Taxes		5,702,521			2,955,015			717,440
General and Administrative Expenses		30,507,114			12,903,845			2,686,176
Depletion of Oil and Natural Gas Properties		17,310,059			12,770,718			3,546,466
Impairment of Oil and Natural Gas Properties		—			61,900,692			—
Depreciation and Amortization		144,492			53,818			30,831
Accretion of Discount on Asset Retirement Obligations		32,449			14,988			4,882
Gain on Sale of Oil and Natural Gas Properties		(7,371,804	)		—			—
Total  Operating Expenses		54,845,245			93,326,209			7,712,741
INCOME (LOSS) FROM OPERATIONS		(3,520,740	)		(65,411,663	)		713,388
OTHER INCOME (EXPENSE)
Interest Expense		(287,934	)		(2,614,240	)		(2,036,032	)
Warrant Revaluation Expense		(7,077,000	)		—			—
Gain on Acquisition of Business, Net		—			5,758,048			—
Other Income (Expense)		2,779			(28,244	)		(22,410	)
Total Other Income (Expense), Net		(7,362,155	)		3,115,564			(2,058,442	)
LOSS BEFORE INCOME TAXES		(10,882,895	)		(62,296,099	)		(1,345,054	)
INCOME TAX PROVISION		—			—			—
NET LOSS		(10,882,895	)		(62,296,099	)		(1,345,054	)
Less: Preferred Stock Dividends and Deemed Dividends		(20,279,197	)		—			—
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	(31,162,092	)	$	(62,296,099	)	$	(1,345,054	)
Net Loss Per Common Share – Basic and Diluted	$	(0.75	)	$	(4.91	)	$	(0.17	)
Weighted Average Shares Outstanding – Basic and Diluted		41,383,277			12,699,544			8,012,158

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

F-4

EMERALD OIL, INC.

(FORMERLY VOYAGER OIL & GAS, INC.)

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2013			2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss	$	(10,882,895	)	$	(62,296,099	)	$	(1,345,054	)
Adjustments to Reconcile Net Loss to Net Cash Provided By (Used For) Operating Activities:
Depletion of Oil and Natural Gas Properties		17,310,059			12,770,718			3,546,466
Impairment of Oil and Natural Gas Properties		—			61,900,692			—
Depreciation and Amortization		144,492			53,818			30,831
Amortization of Debt Discount		—			—			163,356
Amortization of Debt Issuance Costs		127,857			1,929,561			82,191
Accretion of Discount on Asset Retirement Obligations		32,449			14,988			4,882
Net Losses on Commodity Derivatives		2,656,535			215,439			—
Net Cash Settlements Paid on Commodity Derivatives		(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		7,077,000			—			—
Share-Based Compensation Expense		12,885,209			7,318,690			728,546
Changes in Assets and Liabilities:
Increase in Trade Receivables – Oil and Natural Gas Revenues		(200,956	)		(5,267,453	)		(2,951,591	)
Increase in Accounts Receivable – Joint Interest Partners		(27,464,913	)		(4,058,291	)		—
(Increase) Decrease in Other Receivables		556,440			(1,133,849	)		—
(Increase) Decrease in Prepaid Expenses and Other Current Assets		(103,126	)		(54,843	)		90,123
Increase in Other Non-Current Assets		(96,869	)		(100,100	)		—
Increase (Decrease) in Accounts Payable		2,831,342			30,123			(319,349	)
Increase (Decrease) in Accrued Expenses		8,412,533			214,399			(183,557	)
Increase in Other Non-Current Liabilities		56,327			—			—
Increases in Advances from Joint Interest Partners		2,205,538			—			—
Net Cash Provided By (Used For) Operating Activities		6,190,440			4,289,767			(153,156	)
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of Other Property and Equipment		(505,788	)		(172,785	)		(157,892	)
Restricted Cash Deposited		(21,000,512	)		—			—
Increase in Deposits for Acquisitions		(125,368	)		—			—
Use of (Payments for) Prepaid Drilling Costs		100,193			(67,030	)		460,497
Proceeds from Sale of Oil and Natural Gas Properties, Net of Transaction Costs		129,432,743			—			—
Proceeds from Sales of Available for Sale Securities		—			—			242,070
Investment in Oil and Natural Gas Properties		(182,901,806	)		(66,212,818	)		(44,052,953	)
Net Cash Used For Investing Activities		(75,000,538	)		(66,452,633	)		(43,508,278	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Issuance of Common Stock, Net of Transaction Costs		238,354,687			72,167,012			46,602,251
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		—			56,530,730			—
Payments on Revolving Credit Facility		(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		(333,333	)		(1,935,131	)		(389,030	)
Preferred Stock Dividends and Deemed Dividends		(8,832,191	)		—			—
Proceeds from Exercise of Stock Options and Warrants		—			—			16,960
Net Cash Provided by Financing Activities		202,873,157			58,427,978			46,230,181
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		134,063,059			(3,734,888	)		2,568,747
CASH AND CASH EQUIVALENTS – BEGINNING OF PERIOD		10,192,379			13,927,267			11,358,520
CASH AND CASH EQUIVALENTS – END OF PERIOD	$	144,255,438		$	10,192,379		$	13,927,267
Supplemental Disclosure of Cash Flow Information
Cash Paid During the Period for Interest	$	255,776		$	1,154,943		$	1,800,000
Cash Paid During the Period for Income Taxes	$	—		$	—		$	—
Non-Cash Financing and Investing Activities:
Oil and Natural Gas Properties Included in Account Payable	$	60,141,180		$	38,973,137		$	10,252,407
Stock-Based Compensation Capitalized to Oil and Natural Gas Properties	$	1,193,960		$	582,040		$	418,414
Accretion on Preferred Stock Issuance Discount	$	8,626,000		$	—		$	—
Accretion of Preferred Stock Issuance Costs	$	2,816,000		$	—		$	—
Accrued Preferred Stock Dividend and Deemed Dividend	$	—		$	—		$	—
Asset Retirement Obligation Costs and Liabilities	$	676,240		$	164,967		$	100,715
Asset Retirement Obligations Associated With Properties Sold	$	312,625		$	—		$	—
Common Stock Issued for Oil and Natural Gas Properties	$	6,736,935		$	—		$	—
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 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.

(FORMERLY VOYAGER OIL & GAS, INC.)

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (DEFICIT)

FOR THE YEARS ENDED DECEMBER 31, 2013, 2012 AND 2011

	Common Stock
	Shares			Amount			Additional Paid-in Capital			Accumulated Deficit			Total Stockholders’ Equity
Balance – December 31, 2010		6,477,776		$	6,477		$	39,243,374		$	(6,529,027	)	$	32,720,824
Issuance Pursuant to Exercise of Options		572			1			16,959			—			16,960
Net Proceeds from Equity Offering		1,785,714			1,786			46,600,465			—			46,602,251
Restricted Stock Grant Compensation		—			—			226,318			—			226,318
Compensation Related to Stock Warrant and Option Grants		—			—			649,694			—			649,694
Director Fees Related to Stock Option Grants		—			—			270,948			—			270,948
Net Loss		—			—			—			(1,345,054	)		(1,345,054	)
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
Issuance of Preferred Stock		—			—			—			—			—
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

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

F-6

EMERALD OIL, INC.

(FORMERLY VOYAGER OIL & GAS, INC.)

Notes to Consolidated Financial Statements

NOTE 1  ORGANIZATION AND NATURE OF BUSINESS

Description of Operations — Emerald Oil, Inc. (the “Company”), a Montana corporation, is an independent oil and natural gas exploration and production company engaged in the business of acquiring acreage in prospective natural resource plays within the continental United States, primarily focused on the Williston Basin located in North Dakota and Montana. The Company builds net asset value by growing reserves and converting undeveloped assets into producing wells in repeatable and scalable shale oil plays.

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 30 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 shareholders approved a 1-for-7 reverse stock split pursuant to which all shareholders 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 their $250,000 insurance coverage, the Company does not have FDIC coverage on the entire amount of its bank deposits. The Company believes this risk to be minimal. In addition, the Company is subject to Security Investor Protection Corporation protection on a vast majority of its financial assets in the event one of the brokerage firms that the Company utilizes for its investments fails.

Restricted Cash

Restricted cash included in current and long-term assets on the consolidated balance sheets totaled $21 million and $0 at December 31, 2013 and December 31, 2012, respectively.  At December 31, 2013, $11 million of restricted cash relates to cash held in escrow to meet certain post-closing requirements related to the sale of oil and natural gas properties during 2013 (see Note 4 – Oil and Natural Gas Properties). The remaining $10 million relate to a drilling commitment agreement entered into pursuant to oil and natural gas leases acquired during the period.

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, 2013, 2012, or 2011.

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, 2013 and 2012, 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, 2013, 36% 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, 2013, 2012 and 2011 purchases by the following companies exceeded 10% of the total oil and natural gas revenues of the Company.

	For the Years Ended December 31,
	2013			2012		2011
Customer A		24	%		—		—
Customer B		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, 2013, 2012 and 2011, the Company capitalized $3,443,462, $842,418 and $526,630, respectively, of internal salaries, which included $1,193,960, $582,040 and $418,414, 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, 2013 and 2011.

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 year ended December 31, 2013 in the Williston Basin and Sand Wash Basin (see Note 4 – Oil and Natural Gas Properties). A gain was recognized on one transaction 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, 2013, 2012 and 2011, the Company included $3,020,485, $3,625,209 and $6,983,125, respectively, related to expiring leases within costs subject to the depletion calculation.

F-7

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, 2013, 2012 and 2011, the unamortized costs of the Company’s oil and natural gas properties exceeded the ceiling test limit by $0, $51,709,548 and $0 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 $0, $61,900,692 and $0 for the years ended December 31, 2013, 2012, and 2011, 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, 2013, 2012 and 2011 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 $144,492, $53,818 and $30,831 for the years ended December 31, 2013, 2012 and 2011, 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 well is spud or the asset is acquired and a corresponding increase in the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depleted using the units of production method. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.

Revenue Recognition and Natural Gas Balancing

The Company recognizes oil and natural gas revenues from its interests in producing wells when production is delivered and title has transferred to the purchaser, to the extent the selling price is reasonably determinable. The Company uses the sales method of accounting for balancing of natural gas production and would recognize a liability if the existing proven reserves were not adequate to cover the current imbalance situation. As of December 31, 2013 and 2012, 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 shareholders 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 shareholders 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 shareholders 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, 2013, 1,101,726 stock options and 4,068,490 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 2,082,187 nonvested restricted stock units. As of December 31, 2013, there are 4,629,784 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, 2013, 2012 and 2011, the potentially dilutive shares were anti-dilutive and were thus not included in the net loss per share calculation.

F-8

As of December 31, 2013, (i) 2,082,191 nonvested restricted stock units were issued and outstanding and represent potentially dilutive shares; (ii) 464,273 stock options that were issued and presently exercisable and represent potentially dilutive shares; (iii) 694,587 stock options that were granted but are not presently exercisable and represent potentially dilutive shares; (iv) 5,114,633 warrants were issued and presently exercisable, which have an exercise price of $5.77 and represent dilutive shares; (v) 223,293 warrants that were issued and presently exercisable, which have an exercise price of $6.86 and represent potentially dilutive shares; and (vi) 892,858 warrants that were issued and presently exercisable, which have an exercise price of $49.70 and represent potentially dilutive shares. 

Derivative and Other Financial Instruments

Commodity Derivative Instruments

The Company has entered into commodity derivative instruments, utilizing oil derivative swap contracts to reduce the effect of price changes on a portion of future oil production. The Company’s commodity derivative instruments are measured at fair value and are included in the consolidated balance sheet as derivative assets and liabilities. Net gains and losses are recorded based on the changes in the fair values of the derivative instruments. The Company’s valuation estimate takes into consideration the counterparties’ 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.

Joint Ventures

The consolidated financial statements as of December 31, 2013, 2012 and 2011 include the accounts of the Company and its proportionate share of the assets, liabilities, and results of operations of the joint ventures it is involved in.

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.

In connection with the closing of the Emerald Oil North America acquisition, five existing members of the Company’s board of directors resigned, and their vacancies were filled with directors selected by the remaining members of the Company’s board of directors. Also in connection with the closing of the Emerald Oil North America acquisition, the Company entered into employment agreements with six members of management. Following the Emerald Oil North America acquisition, each of the Company’s directors and executive officers entered into indemnification agreements with the Company.

Emerald Oil North America’s $20.3 million in debt obligations assumed by the Company was comprised of $17.7 million to Hartz Energy Capital, LLC (“Hartz”) and $2.5 million plus accrued interest to Parent. Both were paid in full on September 28, 2012.

Interest on the Hartz credit agreement was in the form of an overriding royalty interest in and to all of the oil, gas and other liquid hydrocarbons produced and saved from certain of the Company’s oil and natural gas properties, free of any and all expenses of development, production, transportation, marketing and any other related or similar expenses. The overriding royalty interest was comprised of a 2.15% overriding royalty interest on Emerald Oil North America’s properties in the Williston Basin of North Dakota with a guaranteed 215 net mineral acres underlying the overriding royalty for a period of five years and a 0.9% overriding royalty interest in and to all of the oil, gas and other liquid hydrocarbons produced and saved from the Company’s properties in the Sand Wash Basin of Colorado and Wyoming with a guaranteed 382.5 net mineral acres underlying the overriding royalty for five years. On August 2, 2013, the Company terminated all surviving provisions of the credit agreement including the five year guarantee of providing net mineral acres that underlie the overriding royalty interest by assigning Hartz the Company’s working interest in certain leases of Emerald Oil North America.

The Emerald Oil North America acquisition has been 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

F-9

Pro Forma Operating Results

From July 26, 2012 to December 31, 2012, the Company recognized $194,417 in revenues and $136,196 of expenses relating to Emerald Oil North America, resulting in net income during the year ended December 31, 2012 of $58,221. For the year ended December 31, 2013, the Company recognized $290,126 in revenues and $79,179 of expenses relating to Emerald Oil North America, resulting in net income during the year of $210,947.

The following table reflects the unaudited pro forma results of operations as though the acquisition had occurred on January 1, 2011. The results of operations of the properties acquired during 2011 through 2013, as described above, have been included in the Company’s consolidated financial statements from the closing dates of the acquisitions forward. The pro forma amounts are not necessarily indicative of the results that may be reported in the future:

	Years Ended December 31,
	2012			2011
Revenues	$	27,968,701		$	8,569,107
Net loss	$	(64,707,199	)	$	(1,977,350	)
Net loss per share – basic and diluted	$	(4.74	)	$	(0.20	)
Weighted Average Shares Outstanding – Basic and Diluted		13,639,626			9,674,332

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 January 9, 2013, the Company completed a transaction with an unrelated third party in which the Company acquired leases of oil and natural gas properties in McKenzie County, North Dakota. Pursuant to the purchase and sale agreement and as consideration for the approximate $4.7 million purchase price of the acquired leases, the Company issued 851,315 shares of its common stock at a per share value of $5.50 per share, based on the five-day trading volume-weighted average price of the Company’s common stock prior to closing.

On February 4, 2013, the Company completed a transaction with an unrelated third party in which the Company acquired leases of oil and natural gas properties in McKenzie County, North Dakota. Pursuant to the purchase and sale agreement and as consideration for the approximate $1.9 million purchase price of the acquired leases, the Company issued 313,700 shares of its common stock at a per share value of $6.058 per share, based on the five-day trading volume-weighted average price of the Company’s common stock prior to closing.

On May 8, 2013, the Company acquired approximately 5,874 net acres of undeveloped leasehold in McKenzie County, North Dakota from an unrelated third party for approximately $6.5 million in cash, or approximately $1,100 per net acre.

On August 2, 2013, the Company acquired approximately 3,500 net acres of partially developed leasehold in McKenzie County, North Dakota from an unrelated third party for approximately $10.4 million or approximately $3,000 per net acre.

On August 30, 2013, the Company acquired approximately 3,600 net undeveloped operated acres in McKenzie County, North Dakota from an unrelated third party for approximately $3.6 million, or approximately $1,000 per net acre.

On September 17, 2013, the Company leased approximately 30,672 net undeveloped leasehold acres in McKenzie, Billings and Stark Counties, North Dakota, for approximately $20.2 million, or approximately $660 per net acre. Pursuant to the lease acquired, the Company entered into an agreement with an unrelated third party in which the Company will drill at least five gross wells within the prospect area prior to September 17, 2015. The Company placed $10 million with an escrow agent, of which $2 million per well will be returned to the Company with each well drilled within the term of the escrow agreement. As of December 31, 2013, $4 million of the escrowed funds are classified as a current asset on the consolidated balance sheet, with the remaining $6 million classified as a long-term asset.

On October 9, 2013, the Company closed a transaction with an unrelated third party to acquire approximately 2,866 net acres of undeveloped leasehold in Williams County, North Dakota for approximately $3.2 million, or approximately $1,100 per net acre. On September 20, 2013, the Company leased 313 net acres of undeveloped lease hold in the same area in Williams County, North Dakota for approximately $1.3 million, or approximately $4,100 per net acre.

On December 16, 2013 we acquired approximately 1,101 net acres located in Williams County, North Dakota from an unrelated third party for approximately $5.3 million in cash, or approximately $4,850 per net acre.

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

F-10

NOTE 5  RELATED PARTY TRANSACTIONS

Senior Secured Promissory Notes

On September 22, 2010, Steven Lipscomb and Michael Reger subscribed for $500,000 and $1,000,000 of senior secured promissory notes, respectively. The issuance of the senior secured promissory notes is described in Note 9 to the consolidated financial statements. Mr. Lipscomb is a former director of the Company. Mr. Reger is a brother of J.R. Reger, who is Executive Chairman of the Company and formerly the Chief Executive Officer. The Company’s Audit Committee, which consisted solely of independent directors, reviewed and approved this transaction. The senior secured promissory notes were paid in full on February 10, 2012.

White Deer Energy Investment

In February 2013, the Company entered into a securities purchase agreement with affiliates of 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, or an aggregate $50 million. Pursuant to the purchase agreement, White Deer Energy obtained the right to designate one member of the Company’s Board, and White Deer Energy has designated Thomas J. Edelman as its initial director. Series A Preferred Stock shares were redeemed in full in several redemptions during the year, with the last on October 15, 2013. For additional information regarding the securities purchase agreement with White Deer Energy, see Note 6 — Preferred and Common Stock.

On June 4, 2013, the Company completed a private placement with White Deer Energy, issuing 2,785,600 shares of common stock for approximately $16.2 million after deducting placement agent fees. On October 17, 2013, the Company completed a private placement with White Deer, issuing 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 both transactions. 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 connection with both closings, the Company granted White Deer Energy certain registration rights. The registration rights agreement requires the Company to file a resale registration statement to register the shares of the Company’s common stock and the shares of common stock issuable upon exercise of the warrants held by White Deer Energy if, at any time on or after 90 days from the closing, White Deer Energy makes a written request to the Company for registration of the securities. Under the registration rights agreement, the Company is required to use its commercially reasonable efforts to cause such resale registration statement to become effective within 120 days after its filing. No such request has been made of the Company as of December 31, 2013.

NOTE 6  PREFERRED AND COMMON STOCK

Preferred Stock

The Company has 20,000,000 shares of preferred stock authorized. No shares of preferred stock had been issued as of December 31, 2012.

On February 19, 2013, the Company completed a private offering with affiliates of White Deer Energy pursuant to the terms of the Securities Purchase Agreement, to which, in exchange for a cash investment of $50 million, the Company issued the following to White Deer Energy:

o 500,000 shares of Series A Preferred Stock, $0.001 par value per share;

o 5,114,633 shares of Series B Preferred Stock, $0.001 par value per share; and

o warrants to purchase an initial aggregate 5,114,633 shares of the Company’s common stock, $0.001 par value per share, at an initial exercise price of $5.77 per share. These warrants are exercisable until December 31, 2019.

The Series A Preferred Stock had a cumulative dividend rate of 10% per annum, payable quarterly on each March 31, June 30, September 30 and December 31, commencing on March 31, 2013. If the Company voluntarily or involuntarily liquidated, dissolved or wound up its affairs, the Series A Preferred Stock would have been entitled to receive out of available assets, after satisfaction of liabilities to creditors, if any, and before any distribution of assets is made on the Company’s common stock or any other shares of junior stock, a liquidating distribution in the amount, with respect to each share of Series A Preferred Stock, equal to the sum of (a)(1) on or prior February 19, 2015, $112.50, (2) from February 20, 2015 through February 19, 2016, $110.00, (3) from February 20, 2016 through February 19, 2017, $105.00 and (4) thereafter, $100.00 and (b) the accrued and unpaid dividends thereon (the “Liquidation Preference”). Prior to April 1, 2015, the Company was allowed to pay dividends on the Series A Preferred Stock either (x) in cash or (y) by issuance of (A) additional shares of Series A Preferred Stock valued at the same value as the initial per share purchase price of the Series A Preferred Stock and (B) an additional warrant to purchase shares of common stock; provided that such dividends must be paid in cash unless and until the shareholder approval was obtained to authorize the issuance of any additional warrants and any shares of common stock issuable upon exercise of such additional warrants. On July 10, 2013, the shareholders of the Company authorized the Company to issue at its option additional warrants and shares of common stock issuable upon exercise of such additional warrants as dividends on the Series A Preferred Stock prior to April 1, 2015.

The Company had the option to redeem shares of Series A Preferred Stock in whole or in part at any time at the aggregate Liquidation Preference, subject to a minimum redemption amount equal to the lesser of 50,000 shares or the number of shares then outstanding. Upon a change of control, White Deer Energy had the right to require the Company to purchase the Series A Preferred Stock at the Liquidation Preference. The Series A Preferred Stock did not vote with the Company’s common stock, but had specified approval rights with respect to, among other things, changes to organizational documents that affect the Series A Preferred Stock, payment of dividends on the Company’s common stock or other junior stock, redemptions or repurchases of common stock or other capital stock and incurrence of certain indebtedness. Upon the occurrence of certain events of default under the revolving credit facility with Wells Fargo Bank, N.A. (“Wells Fargo”), White Deer Energy had additional specified approval rights with respect to, among other things, the incurrence or guarantee by the Company of any indebtedness, any change in compensation or benefits of employment or severance agreements with officers and any agreement or arrangement pursuant to which the Company or any of its subsidiaries would pay or incur liability in excess of $1,000,000 over the term of such agreement or arrangement. In addition, upon an event of default, White Deer Energy had the right to require the Company to purchase the Series A Preferred Stock at the Liquidation Preference.

On June 20, 2013, the Company redeemed 150,000 shares of the Series A Preferred Stock for $17,203,767 including $1,875,000 of redemption premium and $328,767 in accrued dividends on the redeemed shares. On August 30, 2013, the Company redeemed 200,000 shares of the Series A Preferred Stock for $22,828,767 including $2,500,000 of redemption premium and $328,767 of accrued dividends on the redeemed shares. On October 15, 2013, the Company redeemed the remaining 150,000 shares of the Series A Preferred Stock for $16,932,534 including $1,875,000 of redemption premium and $57,534 in accrued dividends on the redeemed shares. 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.

For the year ended December 31, 2013, the Company paid dividends on the Series A Preferred Stock of $2,582,191. 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 $5.77 per share and surrendering an equal number of shares of Series B Preferred Stock to the Company. See Note 14 – Derivative Instruments and Price Risk Management – Warrant Liability for further discussion of the warrants.

Upon a change of control or Liquidation Event, as defined in the Securities Purchase Agreement, 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-11

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 is no issuance discount remaining as of December 31, 2013.

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

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

Restricted Stock Awards and Restricted Stock Unit Awards

The Company incurred compensation expense associated with restricted stock and restricted stock units granted of $10,903,696, $4,684,009 and $126,962 for the years ended December 31, 2013, 2012 and 2011, respectively. There were 2,082,187 nonvested restricted stock units and $8,007,835 associated remaining unrecognized compensation expense as of December 31, 2013 which is expected to be recognized over the weighted-average period of 0.90 years. The Company capitalized compensation expense associated with the restricted stock of $851,979, $332,673 and $99,358 to oil and natural gas properties for the years ended December 31, 2013, 2012 and 2011, respectively. Approximately $2,298,661 of the compensation expense associated with restricted stock and restricted stock units during the year ended December 31, 2013 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 537,817 restricted stock units associated with the severance vested subsequent to year end on January 19, 2014, including 442,708 restricted stock units that were nonvested as of December 31, 2013 and 95,109 restricted common shares that were granted on January 17, 2014. There is no remaining unamortized expense associated with the severance as of December 31, 2013. 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, 2011		—		$	—
Granted		—			—
Canceled		—			—
Forfeited		—
Vested		—			—
Non-vested restricted stock and restricted stock units at December 31, 2011		—			—
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

NOTE 7  STOCK OPTIONS AND WARRANTS

Stock Options

The total fair value of all stock options granted during the years ended December 31, 2013, 2012 and 2011 were calculated using the Black-Scholes valuation model based on factors present at the time the options were granted.

F-12

The impact on the Company’s statement of operations of stock-based compensation expense related to options granted for the years ended December 31, 2013, 2012, and 2011 was $1,600,924, $2,634,681 and $334,520, respectively, net of $0 tax. The Company capitalized $1,193,960, $249,367 and $109,688 in compensation to oil and natural gas properties related to outstanding options for the years ended December 31, 2013, 2012 and 2011, respectively. Approximately $456,741 of the compensation expense associated with stock options during the year ended December 31, 2013 related to the modification and accelerated vesting of stock options associated with severance to a prior officer of the Company. A total of 44,643 stock options associated with the severance vested subsequent to year end on January 19, 2014. There is no remaining unamortized expense associated with the severance as of December 31, 2013.

A summary of options for the years ended December 31, 2013, 2012, and 2011 is as follows:

	Number of Options			Weighted Average Exercise Price		Remaining Contractual Term (in Years)		Intrinsic Value
Outstanding at January 1, 2011		139,857			20.51		8.9		2,420,660
Granted		39,284			22.40		—		—
Exercised		(571	)		29.68		—		—
Forfeited or Expired		(28,570	)		19.32		—		—
Outstanding at December 31, 2011		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		4.75	$	—
Stock Options Exercisable at December 31, 2011		51,786		$	18.90		6.9	$	302,750
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

A summary of the status of the Company’s nonvested options as of December 31, 2013 and changes during the year then ended is as follows:

	Number of Options			Weighted-Average Grant-Date Fair Value
Nonvested at December 31, 2011		98,214		$	13.09
Granted		685,713			4.78
Vested		(373,211	)		6.14
Forfeited		—			—
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

For the year ended December 31, 2013, 2012 and 2011, other information pertaining to stock options was as follows:

	2013		2012		2011
Weighted-average per share grant-date fair value of stock options granted	$	4.43	$	4.62	$	14.35
Total intrinsic value of options exercised		211,250		—		3,520
Total grant-date fair value of stock options vested during the year		2,093,999		2,159,307		349,875

The following assumptions were used for the Black-Scholes model to value the options granted during the years ended December 31, 2013, 2012 and 2011.

	2013	2012	2011
Risk free rates	0.48% to 2.12%	0.17% to 1.20%	0.91% to 0.96%
Dividend Yield	0%	0%	0%
Expected volatility	64.64% to 79.50%	69.70% to 78.99%	85.90% to 86.17%
Weighted average expected life	5 years	4 years	3 years

There was $1,518,289 of total unrecognized compensation cost related to nonvested stock options granted as of December 31, 2013. At December 31, 2013, the remaining cost is expected to be recognized over a weighted-average period of 1.37 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, cancelations and the issuance of new options.

Warrants

The impact on the Company’s consolidated statement of operations of stock-based compensation expense related to warrants granted for the years ended December 31, 2013, 2012, and 2011 was $0, $0 and $267,065, respectively, net of $0 tax. The Company capitalized $209,370 in compensation related to outstanding warrants to oil and natural gas properties for the year ended December 31, 2011.

A summary of warrants granted to employees, directors and consultants for the years ended December 31, 2013, 2012 and 2011 is as follows:

	Number of Warrants		Weighted Average Exercise Price		Remaining Contractual Term (in Years)		Intrinsic Value
Outstanding at December 31, 2010		223,293	$	6.86		9.5	$	6,908,681
Granted		—		—		—		—
Exercised		—		—		—		—
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		7.0	$	178,634

F-13

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, 2013, 2012 and 2011, other information pertaining to warrants was as follows:

	2013 (1)		2012		2011
Weighted-average grant-date fair value of warrants granted	$	1.69	$	—	$	2.02
Total intrinsic value of warrants exercised	$	—	$	—	$	—
Total grant-date fair value of warrants vested during the year	$	—	$	—	$	12,625,000

(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, 2013, 2012 and 2011.

	2013 (1)		2012		2011
Risk free rates		—		—		2.02	%
Dividend yield		—		—		0	%
Expected volatility		—		—		75.52	%
Weighted average expected life		—		—		5 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.

The table below reflects the status of warrants outstanding at December 31, 2013:

	Warrants		Exercise Price		Expiration Date
December 1, 2009		37,216	$	6.86	December 1, 2019
December 31, 2009		186,077	$	6.86	December 31, 2019
February 8, 2011		892,858	$	49.70	February 8, 2016
February 19, 2013		5,114,633	$	5.77	December 31, 2019
Total		6,230,784

No warrants expired or were forfeited during the year ended December 31, 2013. 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, 2013.

NOTE 8 REVOLVING CREDIT FACILITY

Wells Fargo Facility

On November 20, 2012, the Company entered into a credit agreement (the “Credit Agreement”) with Wells Fargo, as administrative agent, and the lenders party thereto. The Credit Agreement is a senior secured reserve-based revolving credit facility with a maximum commitment of $400 million (the “Wells Fargo Facility”). As of December 31, 2013, the Wells Fargo Facility was undrawn and had a borrowing base of $75.0 million.

Amounts borrowed under the Wells Fargo Facility will mature on November 20, 2017, and upon such date, any amounts outstanding under the Wells Fargo Facility are due and payable. Redeterminations of the borrowing base will be on a semi-annual basis, with an option to elect an additional redetermination every six months between the semi-annual redeterminations.

The annual interest cost, which is dependent upon the percentage of the borrowing base utilized, is, at the Company’s option, based on either the Alternate Base Rate (as defined in the Credit Agreement) plus 0.75% to 1.75% or the London Interbank Offer Rate (LIBOR) plus 1.75% to 2.75%; provided, in no event may the interest exceed the maximum interest rate allowed by any current or future law.  Interest on ABR Loans is due and payable on a quarterly basis, and interest on Eurodollar Loans is due and payable, at 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, 2013, the annual interest rate on the Wells Fargo Facility was 0.375% which is the minimum commitment fee, as no funds were drawn against the Wells Fargo Facility.

A portion of the Wells Fargo 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, 2013, the Company has not obtained any letters of credit under the Wells Fargo Facility.

Each of the Company’s subsidiaries is a guarantor under the Wells Fargo Facility. The Wells Fargo 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 Agreement 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 Agreement 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 debt to EBITDA for the preceding four fiscal quarters of no more than 3.50 to 1.00, and (c) a fixed charge coverage ratio for any four fiscal quarters of at least 3.00 to 1.00. The Company was in compliance for all covenants as of December 31, 2013.

The principal balance amount on the Credit Agreement was approximately $0 and $23.5 million at December 31, 2013 and December 31, 2012, respectively.

Macquarie Facility

On February 10, 2012, the Company entered into a revolving credit facility (the “Macquarie Facility”) with Macquarie Bank Limited (“MBL”). The Macquarie Facility provided up to a maximum of $150 million in principal amount of borrowings to be used as working capital for exploration and production operations. Initially, $15 million of financing was available under the Macquarie Facility based on reserves, with an additional $50 million available under a development tranche.

On July 26, 2012, the Company entered into an amended and restated credit agreement with MBL to expand the existing availability and outstanding balance under its existing Macquarie Facility and drew $15 million of additional debt on a new third tranche at an initial rate of 9% above the applicable LIBOR and had the potential to draw a maximum of $20 million. The $15 million drawn was used for existing development activities and was paid in full with proceeds from the equity offering completed on September 28, 2012. The remaining balance on the Macquarie Facility was paid in full on November 20, 2012.

NOTE 9  SENIOR SECURED PROMISSORY NOTES

In September 2010, the Company issued senior secured promissory notes in the principal amount of $15 million (the “Notes”) in order to finance future drilling and development activities. Proceeds of the Notes were used primarily to fund developmental drilling on the Company’s significant acreage positions targeting the Williston Basin — Bakken/Three Forks area and the Niobrara formation located in the DJ Basin through the joint venture with Slawson. The Notes were paid in full on February 10, 2012 in conjunction with the Company entering into the Macquarie Facility (see Note 8 – Revolving Credit Facility).

F-14

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 a corresponding increase in the carrying amount of the related long lived asset. The liability is accreted to its present value each period, and the capitalized cost is depleted using the units of production method. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. The fair value of additions to the asset retirement obligations is estimated using valuation techniques that convert future cash flows to a single discounted amount.  Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors (2.5% for each of the years in the three-year period ended December 31, 2013); and (iv) a credit-adjusted risk-free interest rate (average of 7.0% for each of the years in the three-year period ended December 31, 2013). 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, 2013, 2012 and 2011:

	2013			2012		2011
Beginning Asset Retirement Obligation	$	296,074		$	116,119	$	10,522
Revision of Previous Estimates		165,968			—		—
Liabilities Incurred or Acquired		510,271			164,967		100,715
Accretion of Discount on Asset Retirement Obligations		32,449			14,988		4,882
Liabilities Associated with Properties Sold		(312,625	)		—		—
Ending Asset Retirement Obligation	$	692,137		$	296,074	$	116,119

NOTE 11 ACCRUED LIABILITIES

The Company’s accrued liabilities consist of the following:

	December 31,
	2013		2012
Accrued Transaction Adjustments	$	2,067,150	$	—
Oil and Natural Gas Revenue Payable		7,451,394		4,559
Other General and Administrative Expenses		2,303,185		415,930
Total Accrued Liabilities	$	11,821,729	$	420,489

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, 2013, 2012, and 2011 consists of the following:

	2013		2012		2011
Current Income Taxes	$	—	$	—	$	—
Deferred Income Taxes
Federal		—		—		—
State		—		—		—
Total Expense	$	—	$	—	$	—

The following is a reconciliation of the reported amount of income tax expense (benefit) for the years ended December 31, 2013, 2012 and 2011 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:

	2013			2012			2011
Loss Before Taxes	$	(10,882,895	)	$	(62,296,099	)	$	(1,354,054	)
Federal Statutory Rate		35	%		35	%		35	%
Benefit Computed at Federal Statutory Rates		(3,809,013	)		(21,803,635	)		(473,919	)
State Benefit, Net of Federal Benefit		(102,503	)		(1,969,364	)		(68,416	)
Effects of:
Warrant Revaluation		2,476,950			—			—
Nondeductible Expenses		366,203			10,941			—
Other		125,956			(119,872	)		48,919
Change in Valuation Allowance		942,407			23,881,930			493,416
Reported Provision	$	—		$	—		$	—

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

	Year Ended December 31,
	2013			2012
Deferred Tax Assets:
Net Operating Loss Carryforwards (NOLs)	$	36,382,177		$	19,654,346
Stock-based Compensation		3,245,308			1,672,296
Derivatives		323,190			68,438
Equity Investments		116,886			116,488
Oil and Natural Gas Properties		—			6,522,543
Total Deferred Tax Assets		40,067,561			28,034,111
Deferred Tax Liabilities:
Oil and Natural Gas Properties		11,093,181			—
Other		7,353			9,491
Total Deferred Tax Liabilities		11,100,534			9,491
Less: Valuation Allowance		(28,967,027	)		(28,024,620	)
Total Net Deferred Tax Asset	$	—		$	—

At December 31, 2013, the Company has U.S. Federal net operating loss (NOL) carryovers of $102,402,000, which expire at various dates from 2029 through 2033. In addition, the Company had state NOL carryovers of approximately $85,332,000, which expire from 2016 through 2033. 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 NOLs are subject to an annual limitation amount of approximately $1,754,000. Valuation allowances of $28,967,000 and $28,025,000 have been established to offset the Company's net deferred tax assets as of December 31, 2013 and December 31, 2012, respectively, as the realization of these deferred tax assets is not more likely than not.

F-15

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, 2013, 2012 and 2011, 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, 2013 and 2012 relating to unrecognized benefits.

The tax years 2010 through 2013 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 2009 through 2013.

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, 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	)

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, 2012:

	Fair Value Measurements at December 31, 2012 Using
	Quoted Prices In Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Commodity Derivatives – Current Liability (oil swaps and collars)	$	—	$	(206,645	)	$	—
Commodity Derivatives – Long Term Asset (oil swaps and collars)		—		25,397			—
Total	$	—	$	(181,248	)	$	—

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, 2012	$	—
Purchases, issuances, and settlements		(8,626,000	)
Change in Fair Value of Warrant Liability		(7,077,000	)
Transfers		—
Balance, at December 31, 2013	$	(15,703,000	)

The fair value of the warrants upon issuance to White Deer Energy on February 19, 2013 was recorded at $8,626,000. The warrant revaluation expense was $7,077,000 for the year ended December 31, 2013 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.

F-16

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, and the Wells Fargo 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 Wells Fargo Facility approximates fair value because of its floating rate structure. The Company has classified the valuations of the Wells Fargo Facility under Level 2 item of the fair value hierarchy.

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, 2013, the associated volumes and the corresponding weighted average NYMEX reference price:

Settlement Period	Oil (Bbls)		Fixed Price
Oil Swaps
January 1, 2014 – December 31, 2014		103,267	$	91.00
January 1, 2014 – December 31, 2014		31,000		90.05
January 1, 2014 – December 31, 2014		79,000		94.30
January 1, 2014 – December 31, 2014		44,200		94.18
2014 Total/Average		257,467	$	92.44
January 1, 2015 – February 28, 2015		13,876	$	91.00
January 1, 2015 – February 28, 2015		5,000		90.05
January 1, 2015 – February 28, 2015		10,000		94.30
January 1, 2015 – February 28, 2015		8,100		94.18
2015 Total/Average		36,976	$	92.46

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, 2013 and 2012.

	2013			2012
Beginning fair value of commodity derivatives	$	(181,248	)	$	—
Total losses on oil derivatives		(2,656,535	)		(215,439	)
Cash settlements paid on oil derivatives		1,984,778			34,191
Ending fair value of commodity derivatives	$	(853,005	)	$	(181,248	)

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, 2013, using the same Monte Carlo model, using the following assumptions: a term of 1,561 trading days, exercise price of $5.77, stock price of $7.66, volatility rate of 40%, and a risk-free interest rate of 2.5%. As of December 31, 2013, the fair value of the warrants was $15,703,000, and was recorded as a liability on the accompanying consolidated balance sheets. An increase in any of the variables would cause an increase in the fair value of the warrants. Likewise, a decrease in any variable would cause a decrease in the value of the warrants.

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	)

At December 31, 2012, the Company had derivative financial instruments recorded on the consolidated balance sheet as set forth below:

Type of Contract	Balance Sheet Location
Derivative Assets:
Costless Collars	Non-current assets	$	630,441
Costless Collars	Non-current liabilities		(382,872	)
Swap Contracts	Non-current liabilities		(222,172	)
Total Derivative Assets		$	25,397
Derivative Liabilities:
Costless Collars	Current liabilities	$	(194,810	)
Costless Collars	Current assets		365,679
Swap Contracts	Current liabilities		(377,514	)
Total Derivative Liabilities		$	(206,645	)
Net Derivative Position		$	(181,248	)

F-17

NOTE 15 COMMITMENTS AND CONTINGENCIES

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

Acreage 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 $69.3 million in cash. Net daily production from the acreage is approximately 300 barrels of oil equivalent per day as of January 1, 2014, the effective date of the transaction. The Company is currently determining the appropriate purchase price allocation for this transaction.

In connection with the acquisition, the Company drew $35.0 million on the Wells Fargo Facility on February 13, 2014.

In February 2014, the Company entered into a purchase and sale agreement to acquire 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, or $1,750 per acre. The Company paid a deposit of approximately $2.6 million upon execution of the agreement and the transaction is expected to close on or prior to April 1, 2014.

Derivative Instruments

On February 19, 2014, the Company executed the following NYMEX West Texas Intermediate oil derivative swap contract as indicated below:

Settlement Period	Oil (Bbls)		Fixed Price
Oil Swaps
March 1, 2014 – December 31, 2014		251,200	$	97.38
Total		251,200	$	97.38

NOTE 17  QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)

Quarterly data for the years ended December 31, 2013 and 2012 are as follows:

	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

	For the Year Ended December 31, 2012
	First Quarter			Second Quarter			Third Quarter (1)			Fourth Quarter
Total Revenue	$	4,185,898		$	9,014,972		$	5,476,134		$	9,237,542
Expenses	$	3,926,478		$	15,806,435		$	7,835,013		$	65,769,914
Income (Loss) from Operations	$	259,420		$	(6,791,463	)	$	(2,358,879	)	$	(56,532,372	)
Other Income (Expense), Net	$	(515,790	)	$	(169,445	)	$	4,353,721		$	(541,291	)
Net Income (Loss)	$	(256,370	)	$	(6,960,908	)	$	1,994,842		$	(57,073,663	)
Net Cash Provided By (Used In) Operating Activities	$	1,007,098		$	2,329,819		$	4,686,034		$	(3,733,184	)
Net Cash Provided Used in Investing Activities	$	(12,176,316	)	$	(3,604,988	)	$	(20,858,711	)	$	(29,812,618	)
Net Cash Provided By Financing Activities	$	2,181,567		$	449,347		$	45,341,484		$	10,455,580

(1) A reclassification entry was made in 2013 for the Third Quarter of 2012 to reclassify the Gain on Acquisition of Business, Net from Operating Expense to Other Income (Expense), net.

F-18

SUPPLEMENTAL OIL AND NATURAL GAS INFORMATION

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

The reserves at December 31, 2013, 2012 and 2011 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, 2010		183,641			341,559
Revisions of Previous Estimates		21,651			104,077
Extensions, Discoveries and Other Additions		1,548,713			2,876,902
Production		(14,962	)		(95,517	)
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
Proved Developed Reserves:
Proved Developed Reserves at December 31, 2010		35,573			94,783
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 Undeveloped Reserves:
Proved Undeveloped Reserves at December 31, 2010		148,067			246,776
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

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 2013, the Company acquired approximately 0.6 MMBoe in proved reserves in the Low Rider area of McKenzie County, North Dakota in the Williston Basin. As a result of the Company's active development programs in these areas, the Company added 11.7 MMBoe. In 2013, through several transactions, the Company divested of non-operated properties with 5.1 MMBoe.

The Company's reserves have been estimated using deterministic methods. The total proved reserve additions of 11.7 Mboe are comprised of 5.4 MMBoe in proved developed and 6.3 MMBoe in proved undeveloped reserves, all from the Williston Basin.

At December 31, 2013, our estimated proved undeveloped (PUD) reserves were approximately 6.5 MMBoe, a 3.1 MMBoe net increase over the previous year's estimate of 3.4 MMBoe. The increase is largely due to extensions and discoveries net of transfers to proved developed reserves and divestitures totaling 5.8 MMBoe, offset in part by revisions in quantity estimates, all of which were incurred in the Williston Basin. As of December 31, 2013, all of our PUD reserves are less than five years old. The following details the changes in proved undeveloped reserves for 2013 (MBoe):

Beginning proved undeveloped reserves at December 31, 2012	3,397
Undeveloped reserves transferred to developed	(4,903	)
Revisions	(464	)
Purchases	—
Divestitures	(3,219	)
Extensions and discoveries	11,659
Ending proved undeveloped reserves at December 31, 2013	6,470

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, 2012 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-19

	Years Ended December 31,
	2013			2012			2011
Future Cash Inflows	$	1,089,605,300		$	432,483,781		$	297,627,312
Future Production Costs		(375,569,800	)		(135,774,945	)		(78,513,840	)
Future Development Costs		(199,190,700	)		(93,833,711	)		(65,608,984	)
Future Income Taxes		(100,550,387	)		(12,157,129	)		—
Future Net Cash Inflows		414,294,413			190,717,996			153,504,488
10% Annual Discount for Estimated Timing of Cash Flows		(215,922,945	)		(105,433,212	)		(93,879,486	)
Standardized Measure of Discounted Future Net Cash Flows	$	198,371,468		$	85,284,784		$	59,625,002

The twelve month average prices for the year ended December 31, 2013 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, 2013	$	6.17	$	88.80
December 31, 2012	$	5.13	$	85.75
December 31, 2011	$	6.34	$	88.81

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

	Years Ended December 31,
	2013			2012			2011
Beginning of Period	$	85,284,784		$	59,625,002		$	4,775,406
Sales of Oil and Natural Gas Produced, Net of Production Costs		(39,758,105	)		(22,447,837	)		(6,981,743	)
Extensions and Discoveries		209,815,976			38,895,353			45,912,799
Previously Estimated Development Cost Incurred During the Period		12,701,839			11,482,616			7,959,195
Net Change of Prices and Production Costs		5,851,285			(3,003,652	)		6,349,467
Change in Future Development Costs		(19,060,290	)		(13,726,678	)		(197,986	)
Revisions of Quantity and Timing Estimates		62,461,641			(30,431,352	)		1,079,350
Accretion of Discount		8,781,936			5,962,520			477,541
Change in Income Taxes		(36,516,157	)		(2,534,578	)		—
Purchase of Reserves in Place		21,433,173			31,348,048			—
Divestiture of Reserves in Place		(122,297,882	)		—			—
Changes in timing and other		9,673,268			10,115,342			250,973
	$	198,371,468		$	85,284,784		$	59,625,002

Costs Incurred and Capitalized Costs

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

	Year Ended December 31,
	2013		2012		2011
Proved Property Acquisition	$	10,373,374	$	7,799,945	$	—
Unproved Property Acquisition		56,297,987		54,917,350		18,351,743
Exploration Costs		81,650,325		1,939,440		251,566
Development		64,355,298		71,811,058		36,125,604
Total	$	212,676,984	$	136,467,793	$	54,728,913

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, 2013 by year incurred.

	Year Ended December 31,
	Total		2013		2012		2011		Prior Years
Property Acquisition	$	55,190,232	$	41,997,462	$	8,027,326	$	2,788,113	$	2,377,331
Exploration		1,825,083		1,825,083		—		—		—
Drilling		—		—		—		—		—
Total	$	57,015,315	$	43,822,545	$	8,027,326	$	2,788,113	$	2,377,331

F-20