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, 2010
Or
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934.
For the transition period from ________ to ________
 
Commission File No. 001-33999
__________________

NORTHERN OIL AND GAS, INC.
(Exact Name of Registrant as Specified in Its Charter)

Minnesota
 
95-3848122
(State or Other Jurisdiction of Incorporation or Organization)
 
(I.R.S. Employer Identification No.)
 
315 Manitoba Avenue – Suite 200, Wayzata, Minnesota 55391
 
(Address of Principal Executive Offices) (Zip Code)
 
952-476-9800
 
(Registrant’s Telephone Number, Including Area Code)
 
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 Amex Equities Market
 
Securities registered pursuant to Section 12(g) of the Act: None
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act
 
Yes x No ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.
 
Yes ¨ No x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
 
 
 
Yes x No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files.
 
 
 
Yes ¨ No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
 
 
 
x
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
(Do not check if a smaller reporting company)
Smaller Reporting Company ¨
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes ¨ No x
 
The aggregate market value of the registrant’s voting and non-voting common equity held by non-affiliates of the registrant on the last business day of the registrant’s most recently completed second fiscal quarter (based on the closing sale price as reported by the NYSE Amex Equities Market) was approximately $583 million.
 
Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.
 
As of March 1, 2011, the registrant had 63,103,424 shares of common stock issued and outstanding.
 


 
 

 

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the proxy statement related to the registrant’s 2011 Annual Meeting of Shareholders are incorporated by reference into Part III of this annual 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 regarding our financial position, business strategy, plans and objectives of management for future operations, industry conditions, and indebtedness covenant compliance 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, actual or potential future sales, market size, collaborations, and trends or operating results also constitute such forward-looking statements.

Forward-looking statements involve inherent risks and uncertainties, and important factors (many of which are beyond our company’s control) that could cause actual results to differ materially from those set forth in the forward-looking statements, including the following: general economic or industry conditions, nationally and/or in the communities in which our company conducts business, changes in the interest rate environment, legislation or regulatory requirements, conditions of the securities markets, our ability to raise capital, changes in accounting principles, policies or guidelines, financial or political instability, acts of war or terrorism, other economic, competitive, governmental, regulatory and technical factors affecting our company’s operations, products, services and prices.

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. Our company does not undertake, and specifically disclaims, 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”) which 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 TERMS

Unless otherwise indicated in this report, natural gas volumes are stated at the legal pressure base of the state or geographic area in which the reserves are located at 60 degrees Fahrenheit.  Crude oil and natural gas equivalents are determined using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids.

The following definitions shall apply to the technical terms used in this report.

Terms used to describe quantities of crude oil and natural gas:

Bbl” – barrel or barrels.

BOE” – barrels of crude oil equivalent.

Boepd barrels of crude oil equivalent per day.

MBbl” – thousand barrels.

MBoe thousand barrels of crude oil equivalent.

Mcf” – thousand cubic feet of gas.

Mcfe” – thousand cubic feet of gas equivalent.

MMBbls” – million barrels.

MMBoe – million barrels of crude oil equivalent.

MMcf” – million cubic feet of gas.

MMcfe” – million cubic feet of gas equivalent.

MMcfepd” – million cubic feet of gas equivalent per day.

MMcfpd” – million cubic feet of gas per day.
 
Terms used to describe our interests in wells and acreage:

Developed acreage” means acreage consisting of leased acres spaced or assignable to productive wells.  Acreage included in spacing units of infill wells is classified as developed acreage at the time production commences from the initial well in the spacing unit.  As such, the addition of an infill well does not have any impact on a company’s amount of developed acreage.

Development well” is a well drilled within the proved area of a crude oil or natural gas reservoir to the depth of stratigraphic horizon (rock layer or formation) noted to be productive for the purpose of extracting proved crude oil or natural gas reserves.

Dry hole” is an exploratory or development well found to be incapable of producing either crude oil or natural gas in sufficient quantities to justify completion as a crude oil or natural gas well.

Exploratory well” is a well drilled to find and produce crude oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be producing crude oil or natural gas in another reservoir, or to extend a known reservoir.

 
  i

 

Gross acres” refer to the number of acres in which we own a gross working interest.

Gross well” is a well in which we own a working interest.

Infill well” is a subsequent well drilled in an established spacing unit to the addition of an already established productive well in the spacing unit.   Acreage on which infill wells are drilled is considered developed commencing with the initial productive well established in the spacing unit.  As such, the addition of an infill well does not have any impact on a company’s amount of developed acreage.

Net acres” represent our percentage ownership of gross acreage.  Net acres are deemed to exist when the sum of fractional ownership working interests in gross acres equals one (e.g., a 10% working interest in a lease covering 640 gross acres is equivalent to 64 net acres).

“Net acres under the bit” means those leased acres on which wells are spud, drilling, drilled, awaiting completion or completing, and not yet classified as developed acreage, regardless of whether or not such acreage contains proved reserves.  Acreage included in spacing units of infill wells is not considered under the bit because such acreage was already previously classified as developed acreage when the initial well was completed in the subject spacing unit.

Net well” is deemed to exist when the sum of fractional ownership working interests in gross wells equals one.

Productive well” is an exploratory or a development well that is not a dry hole.

Undeveloped acreage” means those leased acres on which wells have not been drilled or completed to a point that would permit the production of economic quantities of crude oil and natural gas, regardless of whether or not such acreage contains proved reserves.  Undeveloped acreage includes net acres under the bit until a productive well is established in the spacing unit.
 
Terms used to assign a present value to or to classify our reserves:

Proved reserves” or “reserves” – Proved crude oil and natural gas reserves are those quantities of crude 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 the estimation.  The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

Proved developed reserves (PDP’s)” – Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional crude oil and natural gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included in “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved developed non-producing reserves (PDNP’s) – Proved crude 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 undeveloped drilling location – A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.

 
ii 

 

Proved undeveloped reserves (PUD’s) – Proved crude oil and natural gas 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 development. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proven effective by actual tests in the area and in the same reservoir.

Probable reserves – are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than proved reserves but which together with proved reserves, are as likely as not to be recovered.
 
Possible reserves – are those additional reserves which analysis of geoscience and engineering data suggest are less likely to be recoverable than probable reserves.
 
Pre-tax PV-10 – means 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.
 
Standardized Measure – means 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.”

 
iii 

 

NORTHERN OIL AND GAS, INC.

TABLE OF CONTENTS

   
Page
Part I
Item 1.
2
Item 1A.
10
Item 1B.
19
Item 2.
20
Item 3.
27
Item 4.
27
     
Part II
Item 5.
27
Item 6.
30
Item 7.
31
Item 7A.
46
Item 8.
47
Item 9.
47
Item 9A.
47
Item 9B.
50
     
Part III
Item 10.
51
Item 11.
52
Item 12.
52
Item 13.
52
Item 14.
52
     
Part IV
Item 15.
52
     
55
F-1

 
NORTHERN OIL AND GAS, INC.

ANNUAL REPORT ON FORM 10-K

FOR FISCAL YEAR ENDED DECEMBER 31, 2010

PART I

Item 1. Business

Overview

Our company took its present form on March 20, 2007, when Northern Oil and Gas, Inc. (“Northern”), a Nevada corporation engaged in our current business, merged with and into our subsidiary, with Northern remaining as the surviving corporation (the “Merger”). Northern then merged into us, and we were the surviving corporation. We then changed our name to Northern Oil and Gas, Inc. As a result of the Merger, Northern was deemed to be the acquiring company for financial reporting purposes and the transaction has been accounted for as a reverse merger. Our primary operations are now those formerly operated by Northern as well as other business activities since March 2007.

On June 30, 2010, Northern completed its reincorporation in the State of Minnesota from the State of Nevada pursuant to a plan of merger between Northern Oil and Gas, Inc., a Nevada corporation, and Northern Oil and Gas, Inc., a Minnesota corporation and wholly-owned subsidiary of the Nevada corporation.  Upon the reincorporation, each outstanding certificate representing shares of the Nevada corporation’s common stock was deemed, without any action by the holders thereof, to represent the same number and class of shares of our company’s common stock.  As of June 30, 2010, the rights of our shareholders began to be governed by Minnesota corporation law and our current articles of incorporation and bylaws.

Our common stock commenced trading on the American Stock Exchange (“AMEX”) on March 26, 2008 under the symbol “NOG.” Our common stock commenced trading on the New York Stock Exchange (“NYSE”) on the NYSE Amex Equities Market platform upon completion of NYSE Euronext’s acquisition of the AMEX.

Business

We are a growth-oriented independent energy company engaged in the acquisition, exploration, development and production of crude oil and natural gas properties, primarily in the Bakken and Three Forks formations within the Williston Basin in North Dakota and Montana.  As of March 1, 2011, we controlled 147,407 net acres in the Williston Basin targeting the Bakken and Three Forks formations and owned working interests in 337 successful discoveries, consisting of 332 targeting the Bakken and Three Forks formations and five targeting Red River structures.  Our current Bakken and Three Forks prospective acreage position will allow us to drill approximately 921 net wells based on six net wells per 960-acre spacing units.  As of March 1, 2011, we had developed 23,279 net acres and had 11,596 net acres under the bit.  We reaffirm our focus and commitment to only the Williston Basin Bakken, Three Forks and Red River plays.
 

We believe that we are able to create value via strategic acreage acquisitions and convert that value or portion thereof into production by utilizing experienced industry partners specializing in the specific areas of interest. We have targeted specific prospects and began drilling for crude oil in the Williston Basin region in the fourth fiscal quarter of 2007.

As an exploration company, our business strategy is to identify and exploit the crude oil producing Bakken and Three Forks formation. We intend to take advantage of our expertise in aggressive land acquisition to pursue exploration and development projects as a non-operating working interest partner, participating in drilling activities primarily on a heads-up basis proportionate to our working interest. Our business does not depend upon any intellectual property, licenses or other proprietary property unique to our company, but instead revolves around our ability to acquire mineral rights and participate in drilling activities by virtue of our ownership of such rights and through the relationships we have developed with our operating partners.



We believe our competitive advantage lies in our ability to acquire property in the Williston Basin in a nimble and efficient fashion.  We historically have acquired properties by purchasing individual or small groups of leases directly from mineral owners or from landmen or lease brokers, as well as purchasing lease packages in identified project areas controlled by specific operators.  We continue to utilize a variety of methods to acquire properties, and are increasingly focusing our efforts on acquiring properties subject to specific drilling projects or included in permitted or drilling spacing units.

We are focused on maintaining a low overhead structure. We believe we are in a position to most efficiently exploit and identify high production crude oil and natural gas properties due to our unique non-operator model through which we are able to diversify our risk and participate in the evolution of technology by the collective expertise of those operators with which we partner. We intend to continue to carefully pursue the acquisition of properties that fit our profile.

Reserves

We completed our initial reservoir engineering calculations in the first fiscal quarter of 2008 and recently completed our most current reservoir engineering calculation as of December 31, 2010.  Based on our independent reservoir engineering firm’s calculation of proved undeveloped reserves as of December 31, 2009, approximately 22% of our proved undeveloped reserves were converted to proved developed reserves during 2010.
 
Based on the results of our December 31, 2010 reserve analysis, our proved reserves increased approximately 158% during 2010 primarily as a result of increased drilling activity involving our acreage and our acquisition of acreage subject to specific drilling projects or included in permitted or drilling spacing units.  We incurred approximately $124 million of capital expenditures for drilling activities during the year ended December 31, 2010, all of which directly contributed to the increase in our proved developed reserves. No other expenditures materially contributed to the development of proved developed reserves in 2010.  We expect that our proved undeveloped reserves will continue to be converted to proved developed producing reserves as additional wells are drilled including our acreage.  We do not have any material amounts of proved undeveloped reserves that have remained undeveloped for five years or more.
 
At year-end, we had developed approximately 15% of our Bakken and Three Forks prospective acreage.  At year end we had 10,748 net acres under the bit, for a total of approximately 31,974 net acres or 23% of our prospective Bakken and Three Forks position which consisted of both developed acreage and net acres under the bit.  The value of our reserves is calculated by determining the present value of estimated future revenues to be generated from the production of our proved reserves, net of estimated lease operating expenses, production taxes and future development costs. All of our proved reserves are located in North Dakota and Montana.
 
Preparation of our reserve report is outlined in our Sarbanes-Oxley Act Section 404 internal control procedures. Our procedures require that our reserve report be prepared by a third-party registered independent engineering firm at the end of every year based on information we provide to such engineer. We accumulate historical production data for our wells, calculate historical lease operating expenses and differentials, update working interests and net revenue interests, obtain updated authorizations for expenditure (“AFEs”) from our operations department and obtain geological and geophysical information from operators. This data is forwarded to our third-party engineering firm for review and calculation. Our Chief Executive Officer provides a final review of our reserve report and the assumptions relied upon in such report.
 
We have utilized Ryder Scott Company, LP (“Ryder Scott”), an independent reservoir engineering firm, as our third-party engineering firm beginning with the preparation of our December 31, 2008 reserve report. The selection of Ryder Scott is approved by our Audit Committee [annually]. Ryder Scott is one of the largest reservoir-evaluation consulting firms and evaluates crude oil and natural gas properties and independently certifies petroleum reserves quantities for various clients throughout the United States and internationally. Ryder Scott has substantial experience calculating the reserves of various other companies with operations targeting the Bakken and Three Forks formations and, as such, we believe Ryder Scott has sufficient experience to appropriately determine our reserves. Ryder Scott utilizes proprietary technology, systems and data to calculate our reserves commensurate with this experience.
 
 
The proved reserves tables below summarize our estimated proved reserves as of December 31, 2010, based upon reports prepared by Ryder Scott.  The reports of our estimated proved reserves in their entirety are based on the information we provide to them. Ryder Scott is a Colorado Registered Engineering Firm (F-1580).  Our primary contact at Ryder Scott is James L. Baird, Senior Vice President. Mr. Baird is a State of Colorado Licensed Professional Engineer (License #41521).
 
In accordance with applicable requirements of the SEC, 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).
 
The reserves set forth in the Ryder Scott 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.  The estimates of the reserves, future production, and income attributable to properties are prepared using the economic software package Aries for Windows, a copyrighted program of Halliburton.
 
To estimate economically recoverable crude 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 the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be demonstrated to be economically producible based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be 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 Ryder Scott report represents only estimates, and should not be construed as being exact quantities. They 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 crude oil and natural gas that cannot be measured in an exact manner. There are numerous uncertainties inherent in estimating crude 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 crude 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 crude 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 crude oil and natural gas reserves that we make may be inaccurate and our actual revenues may be lower than our financial projections.”
 
Ryder Scott prepared two separate reserve reports valuing our proved reserves at December 31, 2010. The reports value only our proved reserves and do not value our probable reserves or our possible reserves. Both tables account for straight-line pricing of crude oil and natural gas at constant prices over the expected life of our wells. Our “SEC Pricing Proved Reserves” were calculated using crude oil and natural gas price parameters established by current SEC guidelines and Financial Accounting Standard Board guidance. Our “Sensitivity Case Proved Reserves” were calculated using higher assumed values for crude oil and natural gas selected at our discretion to better reflect our current expectations because the SEC pricing parameters are significantly lower than current market prices and our average realized price per barrel at December 31, 2010. The Sensitivity Case Proved Reserves table provided below is intended to illustrate reserve sensitivities to the commodity prices.  The Sensitivity Case using the constant average price of $88.91 represents the February 25, 2010 closing WTI crude oil price less our weighted average deduction from spot price for the fiscal year end of 2010.  The “Sensitivity Case Proved Reserves” should not be confused with “SEC Pricing Proved Reserves” as outlined below and does not comply with SEC pricing assumptions, but does comply with all other definitions. 
 
 

SEC Pricing Proved Reserves(1)
 
   
Crude Oil
(barrels)
   
Natural Gas
(cubic feet)
   
Total
 (BOE)(2)
   
Pre-Tax
PV10% Value(3)
 
PDP Properties
    4,857,272       2,698,401       5,307,006     $ 160,307,688  
PDNP Properties
    983,474       815,026       1,119,312     $ 30,829,818  
PUD Properties
    8,152,953       6,936,538       9,309,043     $ 104,374,016  
Total Proved Properties:
    13,993,699       10,449,965       15,735,361     $ 295,511,522  

Sensitivity Case Proved Reserves(1)
 
   
Crude Oil
(barrels)
   
Natural Gas
(cubic feet)
   
Total
 (BOE)(2)
   
Pre-Tax
 PV10% Value(3)
 
PDP Properties
    4,960,356       2,746,567       5,418,117     $ 206,160,609  
PDNP Properties
    1,001,776       829,924       1,140,096     $ 39,942,594  
PUD Properties
    8,269,365       7,035,487       9,441,946     $ 172,593,734  
Total Proved Properties:
    14,231,497       10,611,978       16,000,159     $ 418,696,937  
 
 
 

 
(1)
The SEC Pricing Proved Reserves table above values crude oil and natural gas reserve quantities and related discounted future net cash flows as of December 31, 2010 assuming a constant realized price of $70.46 per barrel of crude oil and a constant realized price of $5.04 per Mcf of natural gas.
 
The Sensitivity Case Proved Reserves table above values crude oil and natural gas reserve quantities and related discounted future net cash flows as of December 31, 2010 assuming a constant realized price of $88.91 per barrel of crude oil and a constant realized price of $5.04 per Mcf of natural gas, which prices are consistent with prior SEC pricing methodology.
 
The Sensitivity Case Proved Reserves table is intended to illustrate reserve sensitivities to the commodity prices.  The “Sensitivity Case Proved Reserves” should not be confused with “SEC Pricing Proved Reserves” as outlined above and does not comply with SEC pricing assumptions, but does comply with all other definitions.  Based on Ryder Scott’s reserve analysis, the increase in the Sensitivity Case reserves is primarily attributed to the positive correlation between higher prices per barrel and longer well lives.
 
The values presented in both tables above were calculated by Ryder Scott.
 
 
(2)
BOE are computed based on a conversion ratio of one BOE for each barrel of crude oil and one BOE for every 6,000 cubic feet (i.e., 6 Mcf) of natural gas.
 
 
(3)
Pre-tax PV10% may be considered a non-GAAP financial measure as defined by the SEC and is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable standardized financial measure. Pre-tax PV10% is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting future income taxes. We believe Pre-tax PV10% is a useful measure for investors for evaluating the relative monetary significance of our crude oil and natural gas properties. We further believe investors may utilize our Pre-tax PV10% as a basis for comparison of the relative size and value of our reserves to other companies because many factors that are unique to each individual company impact the amount of future income taxes to be paid. Our management uses this measure when assessing the potential return on investment related to our crude oil and natural gas properties and acquisitions. However, Pre-tax PV10% is not a substitute for the standardized measure of discounted future net cash flows. Our Pre-tax PV10% and the standardized measure of discounted future net cash flows do not purport to present the fair value of our crude oil and natural gas reserves.  The pre-tax PV10% values of our Total Proved Properties in the tables above differ from the tables reconciling our pre-tax PV10% value on the following page of this Annual Report due to rounding differences in certain tables of Ryder Scott’s reserve report.

Our December 31, 2010 reserve report includes an assessment of proven undeveloped locations for only Bakken and Three Forks prospective acreage, which includes approximately 85% of our Bakken and Three Forks undeveloped acreage.  As of December 31, 2010, our Bakken and Three Forks prospective acreage position will allow us to drill approximately 876 net wells based on six net wells per 960-acre spacing units.

The tables above assume prices and costs discounted using an annual discount rate of 10% without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, or federal income taxes. The “Pre-tax PV10%” values of our proved reserves presented in the foregoing tables may be considered a non-GAAP financial measure as defined by the SEC.
 
 
The following table reconciles the pre-tax PV10% value of our SEC Pricing Proved Reserves to the standardized measure of discounted future net cash flows.
 
SEC Pricing Proved Reserves
Standardized Measure Reconciliation
 
Pre-tax Present Value of estimated future net revenues (Pre-tax PV10%)
  $ 295,511,531  
Future income taxes, discounted at 10%
    (84,898,740 )
Standardized measure of discounted future net cash flows
  $ 210,612,791  

The following table reconciles the pre-tax PV10% value of our Sensitivity Case Proved Reserves to the standardized measure of discounted future net cash flows.
 
Sensitivity Case Proved Reserves
Standardized Measure Reconciliation
 
Pre-tax Present Value of estimated future net revenues (Pre-tax PV10%)
  $ 418,696,969  
Future income taxes, discounted at 10%
    (131,118,861 )
Standardized measure of discounted future net cash flows
  $ 287,578,108  

 
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 crude 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 crude oil and natural gas is not likely to average the pricing parameters used to calculate our proved reserves. As such, the crude oil and natural gas quantities and the value of those commodities ultimately recovered from our properties will vary from reserve estimates.

Additional discussion of our proved reserves is set forth under the heading “Supplemental Oil and Gas Information” to our financial statements included later in this report.

Recent Developments

During 2010, we continued to focus our operations on acquiring leaseholds and drilling exploratory and developmental wells in the Williston Basin. We acquired an aggregate of 56,858 additional net mineral acres during 2010, for an average cost of $1,043 per net acre, primarily in Billings, Burke, Divide, Dunn, Golden Valley, McKenzie, Mountrail, Williams, and Stark Counties, of North Dakota but also in Richland, and Roosevelt of Montana.  During 2010, we participated in the completion of 170 gross wells with a 100% success rate in the Bakken and Three Forks formations.  As of December 31, 2010, our principal assets included approximately 145,220 net acres located in the Williston Basin region of the northern United States and approximately 7,950 net acres located in Yates County, New York, as more fully described under the heading “Properties – Leasehold Properties” in Item 2 of this report.
 
During 2010, we continued to acquire interests in crude oil, gas and mineral leases with the intention of increasing our acreage positions in desired prospects of the Williston Basin. A complete discussion of our significant acquisitions during the past fiscal year is included under the heading “Properties – Recent Acreage Acquisitions” in Item 2 of this report.
 
Production Methods

We primarily engage in crude oil and natural gas exploration and production by participating on a “heads-up” basis alongside third-party interests in wells drilled and completed in spacing units that include our acreage. We typically depend on drilling partners to propose, permit and initiate the drilling of wells. Prior to commencing drilling, our partners are required to provide all owners of crude oil, natural gas and mineral interests within the designated spacing unit the opportunity to participate in the drilling costs and revenues of the well to the extent of their pro-rata share of such interest within the spacing unit. In 2010, we participated in the drilling of all new wells that included any of our acreage. We will assess each drilling opportunity on a case-by-case basis going forward and participate in wells that we expect to meet our return thresholds based upon our estimates of ultimate recoverable crude oil and natural gas, expertise of the operator and completed well cost from each project, as well as other factors. At the present time we expect to participate pursuant to our working interest in substantially all, if not all, of the wells proposed to us.

 
We do not manage our commodities marketing activities internally, but our operating partners generally market and sell crude oil and natural gas produced from wells in which we have an interest. Our operating partners coordinate the transportation of our crude oil production from our wells to 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. The price at which production is sold generally is tied to the spot market for crude oil. Williston Basin Light Sweet Crude from the Bakken source rock is generally 41-42 API crude oil and is readily accepted into the pipeline infrastructure.  The weighted average differential reported to us by our producers during 2010 was $8.97 per barrel below New York Mercantile Exchange (NYMEX) pricing.  Our weighted average differential was approximately $10.09 during the fourth quarter of 2010.  This differential represents the imbedded transportation costs in moving the crude oil from wellhead to refinery and will fluctuate based on availability of pipeline, rail and other transportation methods.
 
Competition

The crude oil and natural gas industry is intensely competitive, and we compete with numerous other crude oil and natural gas exploration and production companies. Some of these companies have substantially greater resources than we have. Not only do they explore for and produce crude oil and natural gas, but also many carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. The operations of other companies may be able to pay more for exploratory prospects and productive crude oil and natural gas properties. They may also have more resources to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit.

Our larger or integrated competitors may have the resources to be better able to absorb the burden of existing, and any changes to federal, state, and local laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to discover reserves and acquire additional properties in the future will be dependent upon our ability and resources to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In addition, we may be at a disadvantage in producing crude oil and natural gas properties and bidding for exploratory prospects, because we have fewer financial and human resources than other companies in our industry. Should a larger and better financed company decide to directly compete with us, and be successful in its efforts, our business could be adversely affected.

Marketing and Customers

The market for crude oil and natural gas that we will produce depends on factors beyond our control, including the extent of domestic production and imports of crude oil and natural gas, the proximity and capacity of natural gas pipelines and other transportation facilities, demand for crude oil and natural gas, the marketing of competitive fuels and the effects of state and federal regulation. The crude oil and natural gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.

Our crude oil production is expected to be sold at prices tied to the spot crude oil markets. Our natural gas production is expected to be sold under short-term contracts and priced based on first of the month index prices or on daily spot market prices. We rely on our operating partners to market and sell our production. Our operating partners involve a variety of exploration and production companies, from large publicly-traded companies to small, privately-owned companies. We do not believe the loss of any single operator would have a material adverse effect on our company as a whole.

Principal Agreements Affecting Our Ordinary Business

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 our company the right to drill and maintain wells in specific geographic areas. All lease arrangements that comprise our acreage positions are established using industry-standard terms that have been established and used in the crude oil and natural gas industry for many years. Some of our leases may be acquired from other parties that obtained the original leasehold interest prior to our acquisition of the leasehold interest.


In general, our lease agreements stipulate five year 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 well is considered “held by production,” meaning the lease continues as long as crude oil is being produced. Other locations within the drilling unit created for a well may also be drilled at any time with no time limit as long as the lease is held by production. Given the current pace of drilling in the Bakken play at this time, we do not believe lease expiration issues will materially affect our North Dakota position.

Governmental Regulation and Environmental Matters

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

Regulation of Crude Oil and Natural Gas Production

Our crude 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 crude oil and natural gas. Such states may also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of crude 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 crude 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 its 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 or injunctions, or both. In the opinion of management, 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 our company, as well as the crude oil and natural gas industry in general.


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 crude 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 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 the Act. 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 will be in substantial compliance with such statutes, any change in these statutes or any reclassification of a species as endangered could subject our company to significant expenses to modify our operations or could force our company to discontinue certain operations altogether.

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 crude 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 crude 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 11 full time employees. Our Chief Executive Officer and Chairman, Michael L. Reger, and our President, Ryan R. Gilbertson, are responsible for all material policy-making decisions. They are assisted in the implementation of our company’s business by our Chief Financial Officer and our Chief Operating Officer and General Counsel. All employees have entered into written employment agreements. As drilling production activities continue to increase, we may hire additional technical or administrative personnel as appropriate. We do not expect a significant change in the number of full time employees over the next 12 months based upon our currently-projected drilling plan. 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 land services and reservoir engineering. We believe that this use of third-party service providers enhances our ability to contain general and administrative expenses.

Office Locations

Our executive offices are located at 315 Manitoba Avenue, Suite 200, Wayzata, Minnesota 55391. Our office space consists of 3,044 square feet leased pursuant to a five-year office lease agreement that commenced in February 2008. We believe our current office space is sufficient to meet our needs for the foreseeable future.


Financial Information about Segments and Geographic Areas

We have not segregated our operations into geographic areas given the fact that all of our production activities occur within the Williston Basin.

Available Information – Reports to Security Holders

Our website address is www.northernoil.com. We make available on this website under “Investor Relations,” free of charge, our annual reports on Form 10-K (formerly Form 10-KSB), quarterly reports on Form 10-Q (formerly Form 10-QSB), current reports on Form 8-K and amendments to those reports 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 internet website at www.sec.gov.

We have also posted to our website our Audit Committee Charter, Compensation Committee Charter, Nominating Committee Charter and our Code of Business Conduct and Ethics, in addition to all pertinent company contact information.

Item 1A. Risk Factors

Risks Related to our Business

The possibility of a global financial crisis may significantly impact our business and financial condition for the foreseeable future.

The credit crisis and related turmoil in the global financial system may adversely impact our business and our financial condition, and we may face challenges if conditions in the financial markets do not improve. Our ability to access the capital markets may be restricted at a time when we would like, or need, to raise financing, which could have a material negative impact on our flexibility to react to changing economic and business conditions. The economic situation could have a material negative impact on operators upon whom we are dependent for drilling our wells, our lenders or customers, causing them to fail to meet their obligations to us. Additionally, market conditions could have a material negative impact on our crude oil hedging arrangements if our counterparties are unable to perform their obligations or seek bankruptcy protection. We believe we will have sufficient capital to fund our 2011 drilling program. However, additional capital would be required in the event that we accelerate our drilling program or that crude oil prices decline substantially resulting in significantly lower revenues.

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

We expect that our cash position, unused credit facility and revenues from crude oil and natural gas sales will be sufficient to fund our 2011 drilling program. However, those funds may not be sufficient to fund both our continuing operations and our planned growth. We may require additional capital to continue to grow our business via acquisitions and to further expand our exploration and development programs. We may be unable to obtain additional capital if and when required.

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 planned expansion of operations in the future.


Any additional capital raised through the sale of equity may 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 crude oil and natural gas industry in particular), our limited operating history, the location of our crude oil and natural gas properties and prices of crude 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 crude oil or natural gas prices on the commodities markets 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 limited operating history, and may not be successful in sustaining profitable business operations.

We have a limited operating history. Our business operations must be considered in light of the risks, expenses and difficulties frequently encountered in establishing a business in the crude oil and natural gas industries. We first generated revenues from operations in the fiscal year ended December 31, 2008. There can be no assurance that our business operations will prove to be successful in the long-term. Our future operating results will depend on many factors, including:
 
 
our ability to raise adequate working capital;
 
 
success of our development and exploration;
 
 
demand for natural gas and crude oil;
 
 
the level of our competition;
 
 
our ability to attract and maintain key management and employees; and
 
 
our ability to efficiently explore, develop and produce sufficient quantities of marketable natural gas or crude oil in a highly competitive and speculative environment while maintaining quality and controlling costs.
 
To sustain profitable operations in the future, we must, alone or with others, successfully manage the factors stated above, as well as continue to develop ways to enhance our production efforts. Despite our best efforts, we may not be successful in our exploration or development efforts, or obtain required regulatory approvals. There is a possibility that some of our wells may never produce natural gas or crude oil.

We are highly dependent on Michael Reger, our Chief Executive Officer, Chairman and Director, and Ryan Gilbertson, President and Director. The loss of either of them, upon whose knowledge, leadership and technical expertise we rely, would harm our ability to execute our business plan.

Our success depends heavily upon the continued contributions of Michael Reger and Ryan Gilbertson, whose knowledge, leadership and technical expertise would be difficult to replace, and on our ability to retain and attract experienced engineers, geoscientists and other technical and professional staff. If we were to lose their services, our ability to execute our business plan would be harmed and we may be forced to cease operations until such time as we are able to suitably replace them.  Mr. Reger and Mr. Gilbertson have entered into employment agreements with our company, however, they may terminate their employment with our company at any time.


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

Our business focus is on the crude oil and natural gas industry in a limited number of properties, primarily in Montana and North Dakota. 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 we would if our business were more diversified, enhancing our risk profile. If we do not diversify our operations, our financial condition and results of operations could deteriorate.

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 increase our reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements with customers will depend on developing and maintaining close working relationships with industry participants and our ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment. These realities are subject to change and our inability to maintain close working relationships with industry participants or continue to acquire suitable property may impair our ability to execute our business plan.

To continue to develop our business, we will endeavor to use the business relationships of our management to enter into strategic relationships, which may take the form of joint ventures with other private parties and contractual arrangements with other crude oil and natural gas companies, including those that supply equipment and other resources that we will use in our business. We may not be able to establish these 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 in order to fulfill our obligations to these partners or maintain our relationships. If sufficient strategic relationships are not established and maintained, our business prospects, financial condition and results of operations may be materially adversely affected.

As a non-operator, our development of successful operations relies extensively on third-parties who, if not successful, could have a material adverse affect on our results of operation.

We have only participated in wells operated by third-parties. Our current ability to develop successful business operations depends on the success of our consultants and drilling partners. As a result, we do not control the timing or success of the development, exploitation, production and exploration activities relating to our leasehold interests. If our consultants and drilling partners are not successful in such activities relating to our leasehold interests, or are unable or unwilling to perform, our financial condition and results of operation would be materially adversely affected.

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

The crude oil and natural gas industry is highly competitive. Other crude oil and natural gas companies may seek to acquire crude oil and natural gas leases and other properties and services we will need to operate our business in the areas in which we expect to operate. This competition is increasingly intense as prices of crude oil and natural gas on the commodities markets have risen in recent years. Additionally, other companies engaged in our line of business may compete with us from time to time in obtaining capital from investors. Competitors include 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 respond adequately to competitive pressures, our results of operation and financial condition may be materially adversely affected.


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

Our strategy envisions the expansion of 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 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 cannot assure that we will 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 financial condition and results of operations may be materially adversely affected.

Our hedging activities could result in financial losses or could reduce our net income, which may adversely affect your investment in our common stock.

We generally expect to enter into swap arrangements from time-to-time to hedge our expected production depending on reserves and market conditions. While intended to reduce the effects of volatile crude oil and natural gas prices, such transactions may limit our potential gains and increase our potential losses if crude 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:
 
 
our 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.
 
Risks Related To Our Industry

Crude oil and natural gas prices are very volatile. A protracted period of depressed crude oil and natural gas prices may adversely affect our business, financial condition, results of operations or cash flows.

The crude oil and natural gas markets are very volatile, and we cannot predict future crude oil and natural gas prices. The price we receive for our crude oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. The prices we receive for our production and the levels of our production depend on numerous factors beyond our control. These factors include, but are not limited to, the following:
 
 
changes in global supply and demand for crude oil and natural gas;
 
 
the actions of the Organization of Petroleum Exporting Countries;
 
 
the price and quantity of imports of foreign crude oil and natural gas;
 
 
political and economic conditions, including embargoes, in crude oil-producing countries or affecting other crude oil-producing activity;


 
the level of global crude oil and natural gas exploration and production activity;
 
 
the level of global crude oil and natural gas inventories;
 
 
weather conditions;
 
 
technological advances affecting energy consumption;
 
 
domestic and foreign governmental regulations;
 
 
proximity and capacity of crude oil and natural gas pipelines and other transportation facilities;
 
 
the price and availability of competitors’ supplies of crude oil and natural gas in captive market areas; and
 
 
the price and availability of alternative fuels.
 
The recent worldwide financial and credit crisis reduced the availability of liquidity and credit to fund the continuation and expansion of industrial business operations worldwide. The shortage of liquidity and credit combined with recent substantial losses in worldwide equity markets led to a worldwide economic recession. The slowdown in economic activity caused by future similar recessions could reduce worldwide demand for energy resulting in lower crude oil and natural gas prices and restrict our access to liquidity and credit.
 
Lower crude oil and natural gas prices may not only decrease our revenues on a per unit basis but also may reduce the amount of crude oil and natural gas that we can produce economically and therefore potentially lower our reserve bookings. A substantial or extended decline in crude oil or natural gas prices may result in impairments of our proved crude oil and natural gas properties and may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures. To the extent commodity prices received from production are insufficient to fund planned capital expenditures, we will be required to reduce spending or borrow to cover any such shortfall. Lower crude oil and natural gas prices may also reduce the amount of our borrowing base under our credit agreement, which is determined at the discretion of the lenders based on the collateral value of our proved reserves that have been mortgaged to the lenders, and is subject to regular redeterminations, as well as special redeterminations described in the credit agreement.

Drilling for and producing crude oil and natural gas are high risk activities with many uncertainties.

Our future success will depend on the success of our development, exploitation, production and exploration activities. Our crude oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable crude oil or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Our cost of drilling, completing and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, many factors may curtail, delay or cancel drilling, including the following:
 
 
delays imposed by or resulting from compliance with regulatory requirements;
 
 
pressure or irregularities in geological formations;
 
 
shortages of or delays in obtaining qualified personnel or equipment, including drilling rigs and CO2;
 
 
equipment failures or accidents; and
 
 
adverse weather conditions, such as freezing temperatures, hurricanes and storms.
 
The presence of one or a combination of these factors at our properties could adversely affect our business, financial condition or results of operations.


Our business of exploring for crude oil and natural gas is risky and may not be commercially successful, and the advanced technologies we use cannot eliminate exploration risk.

Our future success will depend on the success of our exploratory drilling program. Crude 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 produce revenue and our resulting financial performance are significantly affected by the prices we receive for crude oil and natural gas produced from wells on our acreage. Especially in recent years, the prices at which crude 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 influences including, but not limited to, the following:
 
 
domestic and foreign demand for crude oil and natural gas by both refineries and end users;
 
 
the introduction of alternative forms of fuel to replace or compete with crude oil and natural gas;
 
 
domestic and foreign reserves and supply of crude oil and natural gas;
 
 
competitive measures implemented by our competitors and domestic and foreign governmental bodies;
 
 
political climates in nations that traditionally produce and export significant quantities of crude oil and natural gas (including military and other conflicts in the Middle East and surrounding geographic region) and regulations and tariffs imposed by exporting and importing nations;
 
 
weather conditions; and
 
 
domestic and foreign economic volatility and stability.
 
Our expenditures on exploration may not result in new discoveries of crude oil or natural gas in commercially viable quantities. Projecting the costs of implementing an exploratory drilling program is difficult 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. Such data and techniques do not allow the interpreter to know conclusively if hydrocarbons are present or economically producible. In addition, the use of three-dimensional (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 our estimates, or if our exploration efforts do not produce results which meet our expectations, our 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 crude oil and natural gas reserves on an economically viable basis, and our reserves and production may decline as a result.

If we continue to succeed in discovering crude oil and/or natural gas reserves, we cannot assure that these reserves will be capable of 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 crude 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 ability to identify and acquire additional suitable producing properties or prospects, to find markets for the crude oil and natural gas we develop and to effectively distribute our production into our markets.

Future crude 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-downs of connected wells resulting from extreme weather conditions, problems in storage and distribution and adverse geological and mechanical conditions. While we will endeavor to effectively manage these conditions, we cannot be assured of doing so optimally, and we will not be able to eliminate them completely in any case. Therefore, these conditions could diminish our revenue and cash flow levels and result in the impairment of our crude oil and natural gas interests.


Estimates of crude oil and natural gas reserves that we make may be inaccurate and our actual revenues may be lower than our financial projections.

We make estimates of crude oil and natural gas reserves, upon which we base our financial projections. We make these reserve estimates using various assumptions, including assumptions as to crude oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Some of these assumptions are inherently subjective, and the accuracy of our reserve estimates relies in part on the ability of our management team, engineers and other advisors to make accurate assumptions. Economic factors beyond our control, such as crude oil and natural gas prices and interest rates, will also impact the value of our reserves.

Determining the amount of crude oil and natural gas recoverable from various formations where we have exploration and production activities involves great uncertainty. For example, in 2006, the North Dakota Industrial Commission published an article that identified three different estimates of generated crude oil recoverable from the Bakken formation. An organic chemist estimated 50% of the reserves in the Bakken formation to be technically recoverable, a crude oil company estimated a recovery factor of 18%, and values presented in the North Dakota Industrial Commission Oil and Gas Hearings ranged from 3 to 10%.

The process of estimating crude oil and natural gas reserves is complex and will require us to use significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each property. As a result, our reserve estimates will be inherently imprecise. Actual future production, crude oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable crude oil and natural gas reserves may vary substantially from those we estimate. If actual production results vary substantially from our reserve estimates, this could materially reduce our revenues and result in the impairment of our crude oil and natural gas interests.

Drilling new wells could result in new liabilities, which could endanger our interests in our properties and assets.

There are risks associated with the drilling of crude oil and natural gas wells, including encountering unexpected formations or pressures, premature declines of reservoirs, blow-outs, craterings, sour gas releases, fires and spills, among others. The occurrence of any of these events could significantly reduce our revenues or cause substantial losses, impairing our future operating results. We may become subject to liability for pollution, blow-outs or other hazards. We seek to maintain insurance with respect to these hazards; however, such insurance has limitations on liability that may not be sufficient to cover the full extent of such liabilities. The payment of such liabilities could reduce the funds available to us or could, in an extreme case, result in a total loss of our properties and assets. Moreover, we may not be able to maintain adequate insurance in the future at rates that are considered reasonable. Crude oil and natural gas production operations are also subject to all the risks typically associated with such operations, including premature decline of reservoirs and the invasion of water into producing formations.

Decommissioning costs are unknown and may be substantial. Unplanned costs could divert resources from other projects.

We may become responsible for costs associated with abandoning and reclaiming wells, facilities and pipelines which we use for production of crude oil and natural gas reserves. Abandonment and reclamation of these facilities and the costs associated therewith is often referred to as “decommissioning.” We accrue a liability for decommissioning costs associated with our wells, but have not established any cash reserve account for these potential costs in respect of any of our properties. If decommissioning is required before economic depletion of our properties or if our estimates of the costs of decommissioning exceed the value of the reserves remaining at any particular time to cover such decommissioning costs, we may have to draw on funds from other sources to satisfy such costs. The use of other funds to satisfy such decommissioning costs could impair our ability to focus capital investment in other areas of our business.


We may have difficulty distributing our production, which could harm our financial condition.

In order to sell the crude oil and natural gas that we are able to produce, the operators of our wells 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. This situation could be particularly problematic 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 crude oil and natural gas production and may increase our expenses.

Furthermore, weather conditions or natural disasters, actions by companies doing business in one or more of the areas in which we will operate, or labor disputes may impair the distribution of crude oil and/or natural gas and in turn diminish our financial condition or ability to maintain our operations.

Environmental risks may adversely affect our business.

All phases of the crude oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, state and municipal laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances produced in association with crude oil and natural gas operations. The legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Compliance with such legislation can 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 we expect may result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of crude 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.

Our business will suffer if we cannot obtain or maintain necessary licenses.

Our operations require licenses, permits and in some cases renewals of licenses and permits from various governmental authorities. Our ability to obtain, sustain or renew such licenses and permits on acceptable terms is subject to change in regulations and policies and to the discretion of the applicable governmental authorities, among other factors. Our inability to obtain, or our loss of or denial of extension of, any of these licenses or permits could hamper our ability to produce revenues from our operations or otherwise materially adversely affect our financial condition and results of operations.

Challenges to our properties may impact our financial condition.

Title to crude oil and natural gas interests is often not capable of conclusive determination without incurring substantial expense. While we intend to make appropriate inquiries into the title of properties and other development rights we acquire, title defects may exist. 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. If our property rights are reduced, our ability to conduct our exploration, development and production activities may be impaired. To mitigate title problems, common industry practice is to obtain a Title Opinion from a qualified crude oil and natural gas attorney prior to the drilling operations of a well.

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 its efficacy and to avoid obsolescence. The costs of doing so may be substantial and may be higher than the costs that we anticipate 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.

 
Risks Related to our Common Stock

The market price of our common stock is, and is likely to continue to be, highly volatile and subject to wide fluctuations.

The market price of our common stock is likely to continue to be highly volatile and could be subject to wide fluctuations in response to a number of factors, some of which are beyond our control, including:
 
 
dilution caused by our issuance of additional shares of common stock and other forms of equity securities, which we expect to make in connection with future capital financings to fund our operations and growth, to attract and retain valuable personnel and in connection with future strategic partnerships with other companies;
 
 
announcements of new acquisitions, reserve discoveries or other business initiatives by us or our competitors;
 
 
our ability to take advantage of new acquisitions, reserve discoveries or other business initiatives;
 
 
fluctuations in revenue from our crude oil and natural gas business as new reserves come to market;
 
 
changes in the market for crude oil and natural gas commodities and/or in the capital markets generally;
 
 
changes in the demand for crude oil and natural gas, including changes resulting from economic conditions, governmental regulation or the introduction or expansion of alternative fuels;
 
 
quarterly variations in our revenues and operating expenses;
 
 
changes in the valuation of similarly situated companies, both in our industry and in other industries;
 
 
changes in analysts’ estimates affecting our company, our competitors and/or our industry;
 
 
changes in the accounting methods used in or otherwise affecting our industry;
 
 
additions and departures of key personnel;
 
 
announcements of technological innovations or new products available to the crude oil and natural gas industry;
 
 
announcements by relevant governments pertaining to incentives for alternative energy development programs;
 
 
fluctuations in interest rates and the availability of capital in the capital markets; and
 
 
significant sales of our common stock, including sales by selling shareholders following the registration of shares under a prospectus.

Some of these and other factors are largely beyond our control, and the impact of these risks, singly or in the aggregate, may result in material adverse changes to the market price of our common stock and/or our results of operations and financial condition.

Our operating results may fluctuate significantly, and these fluctuations may cause the price of our common stock to decline.

Our operating results will likely vary in the future primarily as the result of fluctuations in our revenues and operating expenses, including the coming to market of crude oil and natural gas reserves that we are able to discover and develop, expenses that we incur, the prices of crude oil and natural gas in the commodities markets and other factors. If our results of operations do not meet the expectations of current or potential investors, the price of our common stock may decline.


Shareholders will experience dilution upon the exercise of options and issuance of common stock under our incentive plans.

As of December 31, 2010, we had options for 265,963 shares of common stock outstanding pursuant to our 2006 Incentive Stock Option Plan. Our 2009 Equity Incentive Plan permits us to issue up to 3,000,000 shares of our common stock either upon exercise of stock options granted under such plan or through restricted stock awards under such plan. As of December 31, 2010, we had issued 1,912,991 shares of common stock pursuant to our 2009 Equity Incentive Plan. No options have been issued under our 2009 Equity Incentive Plan. If the holders of outstanding options exercise those options or our Compensation Committee determines to grant additional stock awards under our incentive plan, shareholders may experience dilution in the net tangible book value of our common stock. Further, the sale or availability for sale of the underlying shares in the marketplace could depress our stock price.

We do not expect to pay dividends in the foreseeable future.

We do not intend to declare dividends for the foreseeable future, as we anticipate that we will reinvest any future earnings in the development and growth of our business. Therefore, investors will not receive any funds unless they sell their common stock, and shareholders may be unable to sell their shares on favorable terms or at all. Investors cannot be assured of a positive return on investment or that they will not lose the entire amount of their investment in our common stock.

We may issue additional stock without shareholder consent.

Our Board of Directors has authority, without action or vote of the shareholders, to issue all or part of our authorized but unissued shares. Additional shares may be issued in connection with future financing, acquisitions, employee stock plans, or otherwise. Any such issuance will dilute the percentage ownership of existing shareholders. We are also currently authorized to issue up to 5,000,000 shares of preferred stock. The Board of Directors can issue preferred stock in one or more series and fix the terms of such stock without shareholder approval. Preferred stock may include the right to vote as a series on particular matters, preferences as to dividends and liquidation, conversion and redemption rights and sinking fund provisions. The issuance of preferred stock could adversely affect the rights of the holders of common stock and reduce the value of the common stock. In addition, specific rights granted to holders of preferred stock could discourage, delay or prevent a transaction involving a change in control of our company, even if doing so would benefit our shareholders, and could also discourage proxy contests and make it more difficult for you and other shareholders to elect directors of your choosing and to cause us to take other corporate actions you desire.

Item 1B. Unresolved Staff Comments

None.


Item 2. Properties

Leasehold Properties

As of December 31, 2010, our principal assets included approximately 153,170 net acres located in the northern region of the United States.  Net acreage represents our percentage ownership of gross acreage.  The following table summarizes our estimated gross and net developed and undeveloped acreage by prospect at December 31, 2010.
 
   
Developed Acreage
   
Undeveloped Acreage
   
Total Acreage
 
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
Bakken and Three Forks
    272,304       20,851       264,785       119,365       537,089       140,216  
Red River
    1,600       374       5,334       4,630       6,934       5,004  
Trenton/Black River, Marcellus and Queenstown-Medina
    -       -       7,950       7,950       7,950       7,950  
Total
    273,904       21,225       278,069       131,945       551,973       153,170  
 
The following table summarizes our estimated gross and net developed and undeveloped acreage by state at December 31, 2010.
 
   
Developed Acreage
   
Undeveloped Acreage
   
Total Acreage
 
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
North Dakota
    266,548       20,088       239,210       104,351       505,758       124,439  
Montana
    7,356       1,137       30,909       19,644       38,265       20,781  
New York
    -       -       7,950       7,950       7,950       7,950  
Total
    273,904       21,225       278,069       131,945       551,973       153,170  
 
The following table summarizes our estimated gross and net developed and undeveloped acreage by county at December 31, 2010.
 
   
Developed Acreage
   
Undeveloped Acreage
   
Total Acreage
 
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
Billings County, ND
    1,920       32       355       317       2,275       349  
Burke County, ND
    8,320       979       27,116       4,892       35,436       5,871  
Divide County, ND
    15,996       1,895       38,277       6,898       54,273       8,793  
Dunn County, ND
    35,791       1,214       34,847       34,163       70,638       35,377  
Golden Valley, ND
          -       320       50       320       50  
McKenzie County, ND
    17,356       787       42,620       19,785       59,976       20,572  
Mercer County, ND
    -       -       5,654       495       5,654       495  
Mountrail County, ND
    162,136       12,344       59,305       26,041       221,441       38,385  
Stark County, ND
    2,560       116       5,992       2,041       8,552       2,157  
Williams County, ND
    22,469       2,721       24,724       9,669       47,193       12,390  
Sheridan County, MT
    1,600       374       5,334       4,630       6,934       5,004  
Richland County, MT
    4,480       431       18,141       11,846       22,621       12,277  
Roosevelt County, MT
    1,276       332       7,434       3,168       8,710       3,500  
Yates County, NY
    -       -       7,950       7,950       7,950       7,950  


Our leasehold properties set forth in the table above are more fully described as follows:
 
 
 
Approximately 349 net acres located in Billings County, North Dakota, where we are targeting the Bakken and Three Forks formations, of which we have approximately 32 net acres determined as developed acreage.  As a non-operator we face the risk of approximately 317 net acres expiring if an operator does not commence the development of operations within the agreed terms of our acquired leases.  Our average expiration occurs in the third quarter of 2014.
 
 
Approximately 5,871 net acres located in Burke County, North Dakota, where we are targeting the Bakken and Three Forks formations, of which we have approximately 979 net acres determined as developed acreage and 405 net acres under the bit.  As a non-operator we face the risk of approximately 4,892 net acres expiring if an operator does not commence or continue the development of operations within the agreed terms of our acquired leases.  Our average expiration occurs in the fourth quarter of 2012.
 
 
Approximately 8,793 net acres located in Divide County, North Dakota, where we are targeting the Bakken and Three Forks formations, of which we have approximately 1,895 net acres determined as developed acreage and 1,125 net acres under the bit.  As a non-operator we face the risk of approximately 6,898 net acres expiring if an operator does not commence or continue the development of operations within the agreed terms of our acquired leases.  Our average expiration occurs in the second quarter of 2013.
 
 
Approximately 35,377 net acres located in Dunn County, North Dakota, where we are targeting the Bakken and Three Forks formations, of which we have approximately 1,214 net acres determined as developed acreage and 2,416 net acres under the bit.  As a non-operator we face the risk of approximately 34,163 net acres expiring if an operator does not commence or continue the development of operations within the agreed terms of our acquired leases.  Our average expiration occurs in the first quarter of 2012.
 
 
Approximately 50 net acres located in Golden Valley County, North Dakota, where we are targeting the Bakken and Three Forks formations, of which we have approximately zero net acres determined as developed acreage.  As a non-operator we face the risk of approximately 50 net acres expiring if an operator does not commence the development of operations within the agreed terms of our acquired leases.  Our average expiration occurs in the second quarter of 2013.
 
 
Approximately 20,572 net acres located in McKenzie County, North Dakota, where we are targeting the Bakken and Three Forks formations, of which we have approximately 787 net acres determined as developed acreage and 2,198 net acres under the bit.  As a non-operator we face the risk of approximately 19,785 net acres expiring if an operator does not commence or continue the development of operations within the agreed terms of our acquired leases.  Our average expiration occurs in the third quarter of 2013.
 
 
Approximately 495 net acres located in Mercer County, North Dakota, where we are targeting the Bakken and Three Forks formations, of which we have approximately zero net acres determined as developed acreage.  As a non-operator we face the risk of approximately 495 net acres expiring if an operator does not commence the development of operations within the agreed terms of our acquired leases.  Our average expiration occurs in the second quarter of 2013.
 
 
Approximately 38,385 net acres located in Mountrail County, North Dakota, where we are targeting the Bakken and Three Forks formations, of which we have approximately 12,344 net acres determined as developed acreage and 2,825 net acres under the bit.  As a non-operator we face the risk of approximately 26,041 net acres expiring if an operator does not commence or continue the development of operations within the agreed terms of our acquired leases.  Our average expiration occurs in the second quarter of 2013.
 
 
Approximately 2,157 net acres located in Stark County, North Dakota, where we are targeting the Bakken and Three Forks formations, of which we have approximately 116 net acres determined as developed acreage and 70 net acres under the bit.  As a non-operator we face the risk of approximately 2,041 net acres expiring if an operator does not commence or continue the development of operations within the agreed terms of our acquired leases.  Our average expiration occurs in the fourth quarter of 2013.
 
 
Approximately 12,390 net acres located in Williams County, North Dakota, where we are targeting the Bakken and Three Forks formations, of which we have approximately 2,721 net acres determined as developed acreage and 972 net acres under the bit.  As a non-operator we face the risk of approximately 9,669 net acres expiring if an operator does not commence or continue the development of operations within the agreed terms of our acquired leases.  Our average expiration occurs in the fourth quarter of 2013.

 
 
Approximately 5,004 net acres located in Sheridan County, North Dakota, representing a stacked pay prospect over which we have significant proprietary 3-D seismic data, of which we have approximately 374 net acres determined as developed acreage.  As a non-operator we face the risk of 4,630 net acres expiring if an operator does not commence the development of operations within the agreed terms of our acquired leases.  We expect all of the non-developed acreage to expire in the first quarter of 2011.
 
 
Approximately 12,277 net acres located in Richland County, Montana, where we are targeting the Bakken and Three Forks formations, of which we have approximately 431 net acres determined as developed acreage and 737 net acres under the bit.  As a non-operator we face the risk of 11,846 net acres expiring if an operator does not commence or continue the development of operations within the agreed terms of our acquired leases.  Our average expiration occurs in the first quarter of 2014.
 
 
Approximately 3,500 net acres located in Roosevelt County, Montana, where we are targeting the Bakken and Three Forks formations, of which we have approximately 332 net acres determined as developed acreage.  As a non-operator we face the risk of 3,168 net acres expiring if an operator does not commence the development of operations within the agreed terms of our acquired leases.  Our average expiration occurs in the first quarter of 2012.
 
 
Approximately 7,950 net acres located in the “Finger Lakes” region of Yates County, New York, where we are targeting natural gas production from the Trenton/Black River, Marcellus and Queenstown-Medina formations.  Our average expiration occurs in the fourth quarter of 2011.
 
We believe the Bakken formation represents one of the most crude oil rich, rapidly developing and exciting plays in the Continental United States. We commenced the development of our Williston Basin properties in late 2007 and increased drilling activities quarter-over-quarter throughout 2008, 2009 and 2010.

Recent Acreage Acquisitions

    In 2010, we acquired leasehold interests covering an aggregate of 56,858 net mineral acres in our key prospect areas. The following discussion summarizes these acquisitions.

In the fourth quarter of 2010, we acquired approximately 18,029 net mineral acres, for an average cost of $954 per net acre, in all of our key prospect areas in the form of both effective leases and top-leases.  The acreage acquisitions involved properties spanning across the counties of Richland and Roosevelt, Montana and counties of Billings, Burke, Dunn, Golden Valley, McKenzie, Mountrail, Stark and Williams, North Dakota.   We did not acquire any properties outside Montana or North Dakota during the fourth quarter of 2010.  These acquisitions consisted of an average of 334 net mineral acres per transaction for an average cost of approximately $954 per net mineral acre.

We generally value acreage subject to near-term drilling activities on a lease-by-lease basis because we believe each lease’s contribution to a subject spacing unit is best assessed on that basis if development timing is sufficiently clear.  Consistent with that approach, the majority of our acreage acquisitions involve properties that are “hand-picked” by us on a lease-by-lease basis for their contribution to a well expected to be spud in the near future, and the subject leases are then aggregated to complete one single closing with the transferor.  As such, we generally view each acreage assignment from brokers, landmen and other parties as involving several separate acquisitions combined into one closing with the common transferor for convenience.  However, in certain instances an acquisition may involve a larger number of leases presented by the transferors as a single package without negotiation on a lease-by-lease basis.  In those instances, we still review each lease on a lease-by-lease basis to ensure that the package as a whole meets our acquisition criteria and drilling expectations.  In December of 2010 we acquired a 50% working interest from Slawson Exploration (“Slawson”) in approximately 14,538 net acres in Richland County, Montana, as more fully described below.  That acquisition accounted for approximately 12.8% of total number of net acres we acquired during 2010.  No other acquisition involved more than 10% of the total acreage we acquired during the year.


The following describes some of our larger acquisitions during the fourth quarter of 2010:

Williams and McKenzie Acreage Acquisition

In December of 2010 we acquired approximately 1,748 net acres for $2,500 per net acre in Williams and McKenzie Counties of North Dakota.  All of the acreage consists of non-operated tracts that are not subject to specific exploration or development agreements.  Several operators have been permitting and drilling wells in close proximity to the acreage, and we expect development of our acreage will commence in 2011.

Slawson Exploration Lambert Prospect

In December of 2010 we acquired a 50% working interest in approximately 14,538 net acres for total consideration of $1,737,483 in Richland County, Montana.  Slawson will be operating the prospect and all drilling and future acquisition costs will be shared pro-rata with Slawson based upon our proportionate working interest in the prospect.  This prospect is in close vicinity of Elm Coulee, and considered an extension of the Southwest Big Sky project, which is also operated by Slawson.

BLM Sale

In December of 2010 we purchased 720 net acres from the Bureau of Land Management for $875 per net acre in Richland County, Montana.  The acreage lies within a selected township that recently experienced a successful test well targeting the Bakken formation, but is not subject to specific exploration or development agreements.

Miscellaneous Acreage Acquisitions

In November 2010 we purchased 506 net acres for $2,000 per net acre in a single spacing unit in McKenzie County, North Dakota.  In December 2010 we purchased 506 net acres for $1,500 per net acre in a separate spacing unit in Richland County, Montana.  As of December 31, 2010, the McKenzie County, North Dakota well was awaiting completion and the Richland County, Montana well was spud.

In December of 2010 we purchased 322 net acres for $1,775 per net acre in Mountrail County, North Dakota, of which 235 net acres is estimated to spud during the first quarter of 2011.

Developed and Undeveloped Acreage

As of December 31, 2010, approximately 21,225 net acres had been developed and approximately 131,945 net acres were undeveloped.  The following table summarizes our estimated gross and net developed and undeveloped acreage by state at December 31, 2010. Net acreage represents our percentage ownership of gross acreage.
 
   
Developed Acreage
   
Undeveloped Acreage
   
Total Acreage
 
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
North Dakota
    266,5478       20,088       239,210       104,351       505,758       124,439  
Montana
    7,356       1,137       30,909       19,644       38,265       20,781  
New York
    -       -       7,950       7,950       7,950       7,950  
Total
    273,904       21,225       278,069       131,945       551,973       153,170  

As a non-operator, we are subject to lease expirations if an operator does not commence the development of operations within the agreed terms of our leases.  All of our leases for undeveloped acreage summarized in the table below will expire at the end of their respective primary terms, unless we renew the existing leases, establish commercial production from the acreage or some other “savings clause” is exercised.  We expect to establish production from most of our acreage prior to expiration of the applicable lease terms however, there can be no guarantee we can do so.  The approximate expiration of our gross and net acres which are subject to expire between 2011 and 2015 and thereafter, are set forth below:

 
 
   
Acres Expiring
 
Year Ended
 
Gross
   
Net
 
December 31, 2011
    52,313       37,395  
December 31, 2012
    110,557       40,184  
December 31, 2013
    78,977       35,072  
December 31, 2014
    25,567       14,347  
December 31, 2015 and thereafter
    10,655       4,947  
      Total
    278,069       131,945  
 
During 2010, leases expired in Sheridan County, Montana covering approximately 17,457 net acres and leases expired in Yates County, New York covering approximately 2,050 net acres.  We believe that the expired acreage was not material to our capital deployed in these prospects.  No leases that expired during 2010 comprised a majority of the acreage in any 640-acre spacing unit.  From our inception to December 31, 2010, we spent approximately $115 million for acreage acquisitions.  The Sheridan County, Montana expired acreage represented less than 1% of our total investment in acreage acquisitions from inception through December 31, 2010.  The Yates County, New York expired acreage represented less than 1% of our total investment in acreage acquisitions from inception through December 31, 2010.  In addition, none of the acreage was included when calculating our reserves at December 31, 2008, 2009 or 2010.  Given our core focus on the Bakken and Three Forks formations in key areas of Montana and North Dakota, we determined it was not in our best interest to re-lease any expiring acreage.  As such, we do not consider the expiration of acreage during 2010 to be material.

Unproved Properties

We had 11.69 net wells drilling and completing as of December 31, 2010.  All properties that are not classified as proven properties are considered unproved properties and, thus, the costs associated with such properties are not subject to depletion.  Once a property is classified as proven, all associated acreage and drilling costs are subject to depletion.

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, and by purchasing lease packages in identified project areas controlled by specific operators.  We generally participate in drilling activities on a heads up basis by electing whether to participate in each well on a well-by-well basis at the time wells are proposed for drilling, with the exception of three defined drilling projects with Slawson.

As of December 31, 2010, we were participating in three defined drilling projects with Slawson covering an aggregate of 9,390 net acres controlled by us.  The Windsor project area includes approximately 3,323 net acres controlled by us, primarily located in Mountrail and surrounding counties of North Dakota.  The Anvil project includes approximately 3,750 net acres controlled by us in Roosevelt and Sheridan Counties of Montana and Williams County, North Dakota.  The South West Big Sky project includes approximately 2,317 total net acres controlled by us in Richland County, Montana.

We believe that the majority of our unproved costs will become subject to depletion within the next five years by proving up reserves relating to its acreage through exploration and development activities, by impairing the 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 be dependent upon the timing of future drilling activities and delineation of our reserves.

Production History

The following table presents information about our produced crude oil and natural gas volumes during each fiscal quarter in 2010 and the year ended December 31, 2010. As of December 31, 2010, we were selling crude oil and natural gas from a total of 311 gross wells.  As of December 31, 2009, we were selling crude oil and natural gas from a total of 179 gross wells, all of which were located within the Williston Basin. As of December 31, 2008, we were selling crude oil and natural gas from a total of 36 gross wells. All data presented below is derived from accrued revenue and production volumes for the relevant period indicated.


   
Year Ended December 31,
 
   
2010
   
2009
   
2008
 
Net Production:
                 
Crude Oil (Bbl)
    849,845       274,328       50,880  
Natural Gas (Mcf)
    234,411       47,305       3,969  
Barrel of Crude Oil Equivalent (BOE)
    888,914       282,212       51,542  
                         
Average Sales Prices:
                       
Crude Oil (per Bbl)
  $ 70.65     $ 60.45     $ 75.63  
Effect of crude oil hedges on average price (per Bbl)
    (0.55 )     (3.60 )     15.31  
Crude Oil net of hedging (per Bbl)
    70.09       56.85       90.94  
Natural Gas and other liquids (per Mcf)
    4.76       3.81       8.19  
Effect of natural gas hedges on average price (per Mcf)
                 
Natural gas and other liquids net of hedging (per Mcf)
    4.76       3.81       8.19  
                         
Average Production Costs:
                       
Crude Oil (per Bbl)
  $ 3.78     $ 2.67     $ 1.37  
Natural Gas (per Mcf)
    0.24       0.19       0.32  
Barrel of Oil Equivalent (BOE)
    3.68       2.63       1.38  

Depletion of crude oil and natural gas properties

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. The following table presents our depletion expenses during 2010, 2009 and 2008.
 
   
Year Ended December 31,
 
   
2010
   
2009
   
2008
(As Adjusted) (1)
 
Depletion of crude oil and natural gas properties
  $ 16,884,563     $ 4,250,983     $ 677,915  
 

(1)
See Note 2 to the financial statements accompanying this report.
 
Drilling and Other Exploratory and Development Activities

The following tables summarize gross and net productive and non productive crude oil wells by state at each of December 31, 2010, 2009 and 2008.  A net well represents our percentage ownership of a gross well.  No wells have been permitted or drilled on any of our Yates County, New York acreage.  The following tables do not include wells that were awaiting completion, in the process of completion or awaiting flowback subsequent to fracture stimulation.  We have not participated in any wells solely targeting natural gas reserves.  We have classified all wells drilled to-date targeting the Bakken and Three Forks formations as development wells, meaning we have not drilled any exploratory wells in North Dakota. As of December 31, 2010, we have had 100% success rate in our North Dakota and Montana Bakken and Three Forks wells.  We participated in the productive exploratory and developmental wells in North Dakota and Montana during the periods indicated below.
 

North Dakota
 
   
Year Ended December 31,
 
   
2010
   
2009
   
2008
 
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
Development Wells:
                                   
Natural gas
                                   
Crude oil
    165       15.73       139       6.63       29       1.38  
Non-productive
                                   
Total Development Wells
    165       15.73       139       6.63       29       1.38  
 
Montana

   
Year Ended December 31,
 
   
2010
   
2009
   
2008
 
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
Exploratory Wells:
                                   
Natural gas
                                   
Crude oil
    2       0.44       1       0.23       2       0.5  
Non-productive
                                   
Total Exploratory Wells
    2       0.44       1       0.23       2       0.5  
                                                 
Development Wells:
                                               
Natural gas
                                   
Crude oil
    3       0.68       5       0.23       1       0.7  
Non-productive
                                   
Total Development Wells
    3       0.68       5       0.23       1       0.7  
                                                 
Total Productive Exploratory and Development Wells
    5       1.12       6       0.46       3       0.12  
 
The following table summarizes our cumulative gross and net productive crude oil wells by state at each of December 31, 2010, 2009 and 2008.

   
Year Ended December 31,
 
   
2010
   
2009
   
2008
 
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
North Dakota
    300       23.90       170       8.17       34       1.54  
Montana
    11       2.13       9       1.02       2       0.50  
Total
    311       26.03       179       9.19       36       2.04  

As of December 31, 2010, we had 47 Bakken or Three Forks wells drilling in the Williston Basin, representing an aggregate of 4.38 net wells. We also had 57 Bakken or Three Forks wells in the Williston Basin awaiting completion, in the process of completion or awaiting flowback subsequent to fracture stimulation, representing an aggregate of 7.31 net wells.

Research and Development

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

 
Reserves

We completed our most recent reservoir engineering calculation as of December 31, 2010. Tables summarizing the results of our most recent reserve report are included under the heading “Business – Reserves” in Item 1 of this report. A complete discussion of our proved reserves is set forth in “Supplemental Oil and Gas Information” to our financial statements included later in this report.

Delivery Commitments

We do not currently have any delivery commitments for product obtained from our wells.

Item 3. Legal Proceedings

On August 23, 2010, plaintiff Donald Rensch filed a three count shareholder derivative action in the United States District Court for the District of Minnesota against our company as nominal defendant, Michael L. Reger, Ryan R. Gilbertson, James R. Sankovitz and Chad D. Winter, James Randall Reger, James Russell Reger, Weldon W. Gilbertson, Douglas M. Polinsky, Joseph A. Geraci, II and Voyager Oil & Gas, Inc. (“Voyager”).  The complaint alleges breach of fiduciary duty of loyalty and usurping of corporate opportunities by Messrs. M. Reger, Gilbertson, Sankovitz and Winter; asserts allegations against Messrs. James Randall Reger, Weldon W. Gilbertson, James Russell Reger, Douglas M. Polinsky and Joseph A. Geraci, II of aiding and abetting our officers in breaching their fiduciary duties and usurping of corporate opportunities in connection with the formation, capitalization, and operation of Plains Energy (Voyager’s predecessor); and asserts a claim against Voyager for tortious interference with a prospective business relationship.  The plaintiff seeks injunctive relief and damages, including imposing on Voyager and all of its assets a constructive trust for our company’s benefit.  We believe that each of the above claims lacks merit and intend to strongly defend our company and each of our current and/or former officers and directors in connection with this lawsuit.  A motion to dismiss the lawsuit in the United States District Court for the District of Minnesota was filed on September 15, 2010.  A hearing on the motion to dismiss was held on February 23, 2011.  As of March 1, 2011, the Court had not issued an order concerning the motion to dismiss.

As of March 1, 2011, our company was a party to one litigation claim arising in the ordinary course of business and seeking the quieting of title for a leasehold interest acquired from a third party.

Our company is subject to litigation claims and governmental and regulatory proceedings arising in the ordinary course of business.  Our management believes that all litigation matters in which we are involved are not likely to have a material adverse effect on our financial position, cash flows or results of operations.

Item 4. Reserved

PART II

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

Market Information

Our common stock commenced trading on the AMEX on March 26, 2008 under the symbol “NOG.”  The high and low sales prices for shares of common stock of our company for each quarter during 2009 and 2010 are set forth below.



   
Sales Price
 
   
High
   
Low
 
Fiscal Year Ended December 31, 2010
           
First Quarter
  $ 15.85     $ 10.95  
Second Quarter
    17.59       12.37  
Third Quarter
    16.94       12.31  
Fourth Quarter
    27.87       17.41  
                 
Fiscal Year Ended December 31, 2009
               
First Quarter
  $ 4.24     $ 2.01  
Second Quarter
    8.89       3.40  
Third Quarter
    8.44       4.74  
Fourth Quarter
    12.66       7.65  

The closing price for our common stock on the NYSE Amex Equities Market on March 1, 2011 was $32.05 per share.

Comparison Chart

The following information in this Item 5 of this Annual Report on Form 10-K is not deemed to be “soliciting material” or to be “filed” with the SEC or subject to Regulation 14A or 14C under the Securities Exchange Act of 1934 or to the liabilities of Section 18 of the Securities Exchange Act of 1934, and will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent we specifically incorporate it by reference into such a filing.

The following graph compares the 44-month cumulative total shareholder returns since completion of our reverse merger on April 13, 2007 of Northern Oil and Gas, Inc., and the cumulative total returns of Standard & Poor’s Composite 500 Index and the Amex Oil Index for the same period.  This graph assumes $100 was invested in the stock or the Index on April 13, 2007 and also assumes the reinvestment of dividends. We have not included any graph for any period prior to April 13, 2007, because there was no active trading in our common stock prior to April 13, 2007 and, as such, data is not available for any period prior to such date.

Graph 1
 
 
*              The following table sets forth the total returns utilized to generate the foregoing graph.

   
4/13/2007
   
12/31/2007
   
12/31/2008
   
12/31/2009
   
12/31/2010
 
Northern Oil and Gas, Inc. (NOG)
  $ 100.00     $ 173.75     $ 65.00     $ 296.00     $ 680.25  
Standard & Poor’s Composite 500 Index
    100.00       104.82       66.04       83.52       96.10  
Amex Oil Index
    100.00       120.91       89.24       96.00       103.40  

Holders

As of March 1, 2011, we had 63,103,424 shares of our common stock outstanding, held by approximately 395 shareholders of record. The number of record holders does not necessarily bear any relationship to the number of beneficial owners of our common stock.

Dividends

The payment of dividends is subject to the discretion of our Board of Directors and will depend, among other things, upon our earnings, our capital requirements, our financial condition, and other relevant factors. We have not paid or declared any dividends upon our common stock since our inception and, by reason of our present financial status and our contemplated financial requirements, do not anticipate paying any dividends upon our common stock in the foreseeable future. We intend to reinvest any earnings in the development and expansion of our business. Any cash dividends in the future to common shareholders will be payable when, as and if declared by our Board of Directors or our Compensation Committee, based upon either the Board’s or the Committee’s assessment of:
 
 
our financial condition and performance;
 
 
earnings;
 
 
need for funds;
 
 
capital requirements;
 
 
prior claims of preferred stock to the extent issued and outstanding; and
 
 
other factors, including income tax consequences, restrictions and any applicable laws.

There can be no assurance, therefore, that any dividends on the common stock will ever be paid.

Recent Sales of Unregistered Securities

None.

 
Item 6. Selected Financial Data
 
    Fiscal Years  
   
2010
   
2009
   
2008
   
2007
   
2006(1)(2)
 
           
(As Adjusted)*
             
Statements of Income Information:
 
Revenues
 
Oil and Gas Sales
  $ 59,488,284     $ 15,171,824     $ 3,542,994     $     $  
Gain (Loss) on Settled Derivatives
    (469,607 )     (624,541 )     778,885              
Mark-to-Market of Derivative Instruments
    (14,545,477 )     (363,414 )                    
Other Revenue
    85,900       37,630                    
Total Revenues
  $ 44,559,100     $ 14,221,499     $ 4,321,879     $     $  
                                         
Operating Expenses
 
Production Expenses
  $ 3,288,482     $ 754,976     $ 70,954     $     $  
Production Taxes
    5,477,975       1,300,373       203,182              
General and Administrative Expense
    7,204,442       3,686,330       2,091,289       4,509,743       76,374  
Depletion Oil and Gas Properties
    16,884,563       4,250,983       677,915              
Depreciation and Amortization
    176,595       91,794       67,060       3,446        
Accretion of Discount on Asset Retirement Obligations
    21,755       8,082       1,030              
Total Expenses
  $ 33,053,812     $ 10,092,538     $ 3,111,430     $ 4,513,189     $ 76,374  
                                         
Income (Loss) from Operations
  $ 11,505,288     $ 4,128,961     $ 1,210,449     $ (4,513,189 )   $ (76,374 )
                                         
Other (Expense) Income
    (168,988 )     135,991       383,891       207,896       267  
                                         
Income (Loss) Before Income Taxes
  $ 11,336,300     $ 4,264,952     $ 1,594,340     $ (4,305,293 )   $ (76,107 )
                                         
Income Tax Provision (Benefit)
    4,419,000       1,466,000       (830,000 )            
                                         
Net Income (Loss)
  $ 6,917,300     $ 2,798,952     $ 2,424,340     $ (4,305,293 )   $ (76,107 )
                                         
Net Income (Loss) Per Common Share – Basic
  $ 0.14     $ 0.08     $ 0.08     $ (0.18 )   $ (0.01 )
                                         
Net Income (Loss) Per Common Share – Diluted
  $ 0.14     $ 0.08     $ 0.07     $ (0.18 )   $ (0.01 )
                                         
Weighted Average Shares Outstanding – Basic
    50,387,203       36,705,267       31,920,747       23,667,119       18,000,000  
                                         
Weighted Average Shares Outstanding - Diluted
    50,778,245       36,877,070       32,653,552       23,667,119       18,000,000  
                                         
Balance Sheet Information:
 
Total Assets
  $ 509,693,965     $ 135,594,968     $ 54,520,399     $ 18,131,464     $ 1,105,935  
Total Liabilities
  $ 74,334,483     $ 12,035,518     $ 4,991,336     $ 224,247     $ 1,143,067  
Shareholders’ Equity (Deficit)
  $ 435,359,482     $ 123,559,450     $ 49,529,063     $ 17,907,217     $ (37,132 )
                                         
Statement of Cashflow Information:
 
Net cash provided by (used for) operating activities
  $ 73,307,220     $ 9,812,910     $ 2,506,492     $ (491,509 )   $ (38,532 )
Net cash provided by (used for) investing activities
  $ (207,893,450 )   $ (71,848,701 )   $ (40,357,962 )   $ (5,078,758 )   $ (255,000 )
Net cash provided by (used for) financing activities
  $ 280,463,559     $ 67,488,447     $ 28,519,526     $ 14,832,992     $ 1,143,467  
 
*See Note 2 to the financial statements accompanying this report.

(1)
From inception on October 5, 2006 through December 31, 2006.
 
(2)
Derived from historical financial statements of Kentex Petroleum, Inc., our company’s predecessor company, as presented in our annual report on Form 10-KSB for the fiscal year ended December 31, 2006.
 
In the third quarter of 2009, we changed our method of accounting for drilling costs from the accrual of drilling costs at the time drilling commenced for a well to recording the costs when amounts are invoiced by operators. Recording drilling costs when the invoices are received from operators is deemed preferable as it better represents our actual drilling costs. The recording of drilling costs in this method also is consistent with other companies in the crude oil and natural gas industry. The change decreased Depletion Expense by $512,794, increased Income Tax Provision by $206,000, and increased Net Income by $306,794 or $0.01 per share on a diluted basis for the nine months ended September 30, 2009. The effect of the change on the three months ended September 30, 2009 was to decrease Depletion Expense by $261,870, increase Income Tax Provision by $105,000 and to Increase Net Income by $156,870 or $0.00 per share on a diluted basis.
 
Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion should be read in conjunction with the “Selected Financial Data” in Item 6 and the Financial Statements and Accompanying Notes appearing elsewhere in this report.

Overview and Outlook

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

As of March 1, 2011, we controlled the rights to mineral leases covering approximately 147,407 net acres prospective for the Bakken and Three Forks and, we acquired 7,191 net acres at an average price of $1,956 per acre, of which 40% or 2,842 net acres were permitted as of March 1, 2011.  Our goal is to continue to explore for and develop hydrocarbons within the mineral leases we control as well as continue to expand our acreage position should opportunities present themselves.  To accomplish our objectives we must achieve the following;
 
 
Continue to develop our substantial inventory of high quality core Bakken acreage with results consistent with those to-date;
 
 
Retain and attract talented personnel;
 
 
Continue to be a low-cost producer of hydrocarbons;
 
 
Actively manage our cost structure and focus on accretive acquisitions; and
 
 
Continue to manage our financial obligations to access the appropriate capital needed to develop our position of primarily undrilled acreage.

The following table 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,
 
   
2010
   
2009
   
2008
(As Adjusted) (1)
 
Net Production:
                 
Oil (Bbl)
    849,845       274,328       50,880  
Natural Gas (Mcf)
    234,411       47,305       3,969  
                         
Net Sales:
                       
Oil Sales
  $ 58,020,694     $ 14,977,556     $ 3,510,597  
Natural Gas
    1,467,590       194,268       32,397  
Gain (Loss) on Settled Derivatives
    (469,607 )     (624,541 )     778,885  
Mark-to-Market of Derivative Instruments
    (14,545,477 )     (363,414 )        
Other Revenue
    85,900       37,630          
Total Revenues
    44,559,100       14,221,499       4,321,879  
                         
Average Sales Prices:
                       
Oil (per Bbl)
    70.65       60.45       75.63  
Effect of Oil Hedges on Average Price (per Bbl)
    (0.55 )     (3.60 )     15.31  
Oil Net of Hedging (per Bbl)
    70.09       56.85       90.94  

 
   
Year Ended December 31,
 
   
2010
   
2009
   
2008
(As Adjusted) (1)
 
Natural Gas (per Mcf)
    4.76       3.81       8.19  
Effect of Natural Gas Hedges on Average Price (per Mcf)
                 
Natural gas net of hedging (per Mcf)
    4.76       3.81       8.19  
                         
Operating Expenses:
                       
Production Expenses
    3,288,482       754,976       70,954  
Production Taxes
    5,477,975       1,300,373       203,182  
General and Administrative Expense (Including Share Based Compensation)
    7,204,442       3,686,330       2,091,289  
Depletion of Oil and Gas Properties (10)
    16,884,563       4,250,983       677,915  
 

(1)
 See Note 2 to the financial statement accompanying this report.
 
Results of Operations for the periods ended December 31, 2009 and December 31, 2010.

During 2009 and 2010 we significantly increased our drilling activities, generated income and achieved net earnings for both the 2009 and 2010 fiscal years.  As of December 31, 2010, we have developed approximately 15% of our total Bakken and Three Forks prospective drillable acreage inventory (assuming one well per 960-acre spacing unit) and we expect to continue to add substantial volumes of production on a quarter-over-quarter basis going forward into the foreseeable future.  We are predominately weighted to 640 spacing units compared to 1,280 spacing units, however we believe we will eventually grow into an average spacing unit size of 960 net acres per spacing unit over time as our acreage continues to be developed.

As of December 31, 2010, we had established production from 311 gross (26.03 net) wells in which we hold working interests, versus 179 gross (9.19 net) wells which had established production as of December 31, 2009. Our production at December 31, 2010 approximated 5,019 barrels of crude oil per day, compared to approximately 1,508 barrels of crude oil per day as of December 31, 2009.

We drilled with a 100% success rate in 2009 and 2010 with 104 gross and 11.69 net Bakken or Three Forks wells drilling, awaiting completion or completing as of December 31, 2010.  As of March 1, 2011, we had 136 gross and 13.32 net Bakken or Three Forks wells drilling, awaiting completion, or completing.  We have spud approximately 4 net Bakken or Three Forks wells and expect to spud an additional 4.6 net wells in the first quarter of 2011.

Our revenues, costs and net income increased in 2010 compared to 2009 as we continued our development plans and significantly increased our production.  Revenues for the year ended December 31, 2010 were $44,559,100, compared to $14,221,499 for the year ended December 31, 2009.  The increase in revenue is primarily due to our continued addition of wells and an increase in our average realized crude oil prices period-over-period. We have added wells each quarter since the first quarter of 2008 and, in particular, added production from 16.85 additional net wells during 2010.  During 2010, we realized a $70.09 average price per barrel of crude oil (after the effect of settled hedges), compared to a $56.85 average price per barrel of crude oil (after the effect of settled hedges) during 2009.

We realized net income of $6,917,300 (representing approximately $0.14 per diluted share) for the year ended December 31, 2010, and net income of $2,798,952 (representing approximately $0.08 per diluted share) for the year ended December 31, 2009.  The increase in net income is primarily due to our continued addition of crude oil and natural gas production from new wells and higher realized commodity prices in 2010 compared to 2009, partially offset by an increase in unrealized mark-to-market hedging losses.

Total operating expenses were $33,053,812 for the year ended December 31, 2010, compared to total operating expenses of $10,092,538 for the year ended December 31, 2009.  The increase in operating expenses is due primarily to increased production expenses, production taxes, depletion and general and administrative expenses associated with our continued addition of crude oil and natural gas production from new wells.
 
 
During the year ended December 31, 2010, we had production expenses of $3,288,482, compared to production expenses of $754,976 during the year ended December 31, 2009.  The increase in production expense is primarily a result of more mature wells utilizing artificial lift and the general aging of our production.

During the year ended December 31, 2010, we incurred production taxes of $5,477,975, compared to production taxes of $1,300,373 during the year ended December 31, 2009. The increase in production taxes is primarily due to the continued addition of producing oil and gas properties and related sales.

We recorded depletion of $16,884,563 during the year ended December 31, 2010, compared to depletion of $4,250,983 during the year ended December 31, 2009.  The increase in depletion is primarily due to the addition of proven properties subject to the depletion calculation. Depletion expense for fiscal year 2010 was $18.99 per BOE, compared to $15.06 per BOE, for fiscal year 2009.  We expect depletion per BOE to remain consistent in 2011 compared to 2010.

We had general and administrative expenses of $7,204,442 and $3,686,330 during the years ended December 31, 2010 and 2009, which included $3,638,309 and $2,452,823 net of share based compensation expense, respectively. The increase in general and administrative expense is primarily due to the increase in share based compensation, personnel, and travel expenses.  We expect general and administrative expenses to remain consistent in 2011 compared to 2010.

Non-GAAP net income for the year ended December 31, 2010, excluding unrealized mark-to-market hedging losses, was $15,813,777 (representing approximately $0.31 per diluted share) as compared to non-GAAP net income of $3,022,366 (representing approximately $0.08 per diluted share) for the year ended December 31, 2009, excluding unrealized mark-to-market hedging gains. The increase in non-GAAP net income is primarily due to our continued addition of crude oil and natural gas production from new wells and higher realized commodity prices in 2010 compared to 2009.
We define Adjusted EBITDA as net income before (i) interest expense, (ii) income taxes, (iii) depreciation, depletion and amortization, (iv) accretion of abandonment liability, (v) pre-tax unrealized gain and losses on commodity risk and (vii) non-cash expenses relating to share based payments recognized under ASC Topic 718.  Adjusted EBITDA for the year ended December 31, 2010 was $47,114,199 (representing approximately $0.93 per diluted share), compared to Adjusted EBITDA of $10,747,826 (representing approximately $0.29 per diluted share) for the year ended December 31, 2009.  The increase in Adjusted EBITDA is primarily due to our continued addition of crude oil and natural gas production from new wells and higher realized commodity prices in 2010 compared to 2009.

We believe the use of non-GAAP financial measures provides useful information to investors to gain an overall understanding of our current financial performance.  Specifically, we believe the non-GAAP results included herein provide useful information to both management and investors by excluding certain expenses and unrealized commodity gains and losses that our management believes are not indicative of our core operating results.  In addition, these non-GAAP financial measures are used by management for budgeting and forecasting as well as subsequently measuring our performance, and we believe that we are providing investors with financial measures that most closely align to our internal measurement processes.  We consider these non-GAAP measures to be useful in evaluating our core operating results as they more closely reflect our essential revenue generating activities and direct operating expenses (resulting in cash expenditures) needed to perform these revenue generating activities.  Our management also believes, based on feedback provided by the investment community, that the non-GAAP financial measures are necessary to allow the investment community to construct its valuation models to better compare our results with our competitors and market sector.

The non-GAAP financial information is presented using consistent methodology from year-to-year.  These measures should be considered in addition to results prepared in accordance with GAAP.  In addition, these non-GAAP financial measures are not based on any comprehensive set of accounting rules or principles.  We believe that non-GAAP financial measures have limitations in that they do not reflect all of the amounts associated with our results of operations as determined in accordance with GAAP and that these measures should only be used to evaluate our results of operations in conjunction with the corresponding GAAP financial measures.

 
Net income excluding unrealized mark-to-market hedging gains (losses) and Adjusted EBITDA are non-GAAP measures.  A reconciliation of these measures to GAAP is included below:

Northern Oil and Gas, Inc.
 
Reconciliation of Adjusted EBITDA
 
                   
   
Year Ended December 31,
 
   
2010
   
2009
   
2008
 
   
 
   
 
   
As Adjusted (1)
 
Net Income
  $ 6,917,300     $ 2,798,952     $ 2,424,340  
Add Back:
                       
Income Tax Provision (Benefit)
    4,419,000       1,466,000       (830,000 )
Depreciation, Depletion,
                       
Amortization and Accretion
    17,082,913       4,350,859       746,005  
Share Based Compensation
    3,566,133       1,233,507       105,375  
Mark-to-Market Derivative Instruments
    14,545,477       363,414       -  
Interest Expense
    583,376       535,094       28,976  
Adjusted EBITDA
  $ 47,114,199     $ 10,747,826     $ 2,474,696  
Adjusted EBITDA Per Common Share - Basic
  $ 0.94     $ 0.29     $ 0.08  
Adjusted EBITDA Per Common Share - Diluted
  $ 0.93     $ 0.29     $ 0.08  
Weighted Average Shares Outstanding – Basic
    50,387,203       36,705,267       31,920,747  
Weighted Average Shares Outstanding - Diluted
    50,778,245       36,877,070       32,653,552  
 

(1)
See Note 2 to the financial statement accompanying this report.

 
Northern Oil and Gas, Inc.
 
Reconciliation of Adjusted EBITDA Per Common Share – Basic
 
                   
   
Year Ended December 31,
 
   
2010
   
2009
   
2008
 
               
As Adjusted (1)
 
Net Income (Loss) Per Common Share - Basic
  $ 0.14     $ 0.08     $ 0.08  
(As Reported)
                       
Add Back:
                       
      Income Tax Provision (Benefit)
    0.09       0.04       (0.02 )
     Depreciation, Depletion, Amortization, and Accretion
    0.34       0.12       0.02  
Share Based Compensation
    0.07       0.03       0.00  
Mark-to-Market Derivative Instruments
    0.29       0.01       -  
Interest Expense
    0.01       0.01       0.00  
Adjusted EBITDA Per Common Share - Basic
  $ 0.94     $ 0.29     $ 0.08  
(Adjusted for Non-GAAP Measurement)
                       
 
(1)
See Note 2 to the financial statement accompanying this report.
 
 
Northern Oil and Gas, Inc.
 
Reconciliation of Adjusted EBITDA Per Common Share – Diluted
 
                   
   
Year Ended December 31,
 
   
2010
   
2009
   
2008
 
               
As Adjusted (1)
 
Net Income (Loss) Per Common Share - Diluted
  $ 0.14     $ 0.08     $ 0.07  
(As Reported)
                       
Add Back:
                       
      Income Tax Provision (Benefit)
    0.09       0.04       (0.02 )
     Depreciation, Depletion, Amortization, and Accretion
    0.34       0.12       0.02  
Share Based Compensation
    0.07       0.03       0.01  
Mark-to-Market Derivative Instruments
    0.28       0.01       -  
Interest Expense
    0.01       0.01       0.00  
Adjusted EBITDA Per Common Share - Diluted
  $ 0.93     $ 0.29     $ 0.08  
(Adjusted for Non-GAAP Measurement)