NORTHERN OIL & GAS, INC. - FORM 10-K/A

Attached files

file	filename
EX-32.1 - CERTIFICATION OF CEO/CFO PURSUANT TO SECTION 906 - NORTHERN OIL & GAS, INC.	nog114332_ex32-1.htm
EX-23.2 - CONSENT OF RYDER SCOTT COMPANY, L.P. - NORTHERN OIL & GAS, INC.	nog114332_ex23-2.htm
EX-31.1 - CERTIFICATION OF CEO PURSUANT TO SECTION 302 - NORTHERN OIL & GAS, INC.	nog114332_ex31-1.htm
EX-31.2 - CERTIFICATION OF CFO PURSUANT TO SECTION 302 - NORTHERN OIL & GAS, INC.	nog114332_ex31-2.htm
EX-23.1 - CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM - NORTHERN OIL & GAS, INC.	nog114332_ex23-1.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K/A
(AMENDMENT NO. 1)


(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
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934.
For the transition period from ________ to ________

Commission File No. - 001-33999



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
(Title of Class)

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

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files. Yes o No o

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

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


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

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

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter.

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.

EXPLANATORY NOTE

Northern Oil and Gas, Inc. is filing this Amendment No. 1 to its Annual Report on Form 10-K for the fiscal year ended December 31, 2010, originally filed with the Securities and Exchange Commission (the “SEC”) on March 4, 2011 (the “Original Report”).

This Amendment is being filed to (i) amend Item 1 of Part I and Note 1 to the financial statements included in Item 8 of Part II to eliminate the references to the total number of wells in which we may potentially participate and (ii) amend Items 11 and 13 of Part III to enhance certain disclosures incorporated by reference into the Original Report from our proxy statement for the Annual Meeting of Shareholders held June 8, 2011. Pursuant to Rule 12b-15 promulgated under the Securities Exchange Act of 1934, as amended, this Amendment sets forth the complete text of each item as amended.

Except as expressly set forth above, the Original Report has not been amended, updated or otherwise modified. This Amendment does not reflect events occurring after the filing of the Original Report or update those disclosures regarding events that occurred subsequent to the end of the fiscal year ended December 31, 2010. All other information is unchanged and reflects the disclosures made at the time of the filing of the Original Report.

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.

“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.

“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.

iii

“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.”

NORTHERN OIL AND GAS, INC.

TABLE OF CONTENTS


		Page
Part I
Item 1.	Business	2
Part II
Item 8.	Financial Statements and Supplementary Data	11
Part III
Item 11.	Executive Compensation	12
Item 13.	Certain Relationships and Related Transactions, and Director Independence	24
Part IV
Item 15.	Exhibits and Financial Statement Schedules	26

Signatures
Financial Statements		F-1
Financial Statement Schedules

NORTHERN OIL AND GAS, INC.

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 Texas 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.

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.

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.

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.

PART II

Item 8. Financial Statements and Supplementary Data

The financial statements and supplementary financial information required by this item are included on the pages immediately following the Index to Financial Statements appearing on page F-1.

PART III

Item 11. Executive Compensation

Compensation Discussion and Analysis

Named Executive Officers

This Compensation Discussion and Analysis provides information about the 2010 compensation program for the following named executive officers:


	Michael L. Reger	Chief Executive Officer, Chairman of the Board and Director
	Ryan R. Gilbertson	President and Director
	Chad D. Winter	Chief Financial Officer
	James R. Sankovitz	Chief Operating Officer, General Counsel and Secretary

Overview

Our compensation committee is responsible for establishing director and executive officer compensation, policies and programs to insure that they are consistent with our compensation philosophy and corporate governance guidelines. The compensation committee is authorized to make plan awards to our employees to recognize individual and company-wide achievements as the committee deems appropriate. Our compensation committee has annually reviewed and approved base salary and incentive compensation levels, employment agreements and benefits of executive officers and other key executives.

We have implemented a compensation program that is designed to reward our management for maximizing shareholder value and ensuring the long-term stability of our company. Our compensation program is intended to reward individual accomplishments, team success and corporate results. It also recognizes the varying responsibilities and contributions of each employee and is intended to foster an ownership mentality among our management team.

Compensation Consultant

In 2010, the compensation committee engaged BDO Seidman (“BDO”) as an independent consultant to prepare an analysis of peer company compensation practices and advise the compensation committee on the reasonableness and appropriateness of compensation for the leadership employees of our company. The benchmarks used for the executive compensation comparisons included various publicly-traded crude oil and natural gas exploration and production companies that it has deemed to be peer companies, including (in alphabetical order) Abraxas Petroleum Corp., Callon Petroleum Co., Carrizo Oil & Gas, Inc., Double Eagle Petroleum Co., Energy XXI (Bermuda) Limited, EV Energy Partners LP, GMX Resources Inc., Goodrich Petroleum Corp., Kodiak Oil and Gas, PetroQuest Energy Inc., Rex Energy Corporation Stone Energy Corp. and Swift Energy Co.

BDO Seidman concluded that the award of equity, in combination with prior year awards and a continuation of cash compensation at levels suggested by our compensation committee, sets our executive officers’ compensation at market-competitive levels for the next four years, and the vesting terms of the awards establish a meaningful incentive to remain with our company. The four-year incentive plan represents a multi-year plan designed to incentivize our executive team over a long-term basis.

Role of Executives in Establishing Compensation

The compensation committee makes the final determination of all compensation paid to our named executive officers and is involved in all compensation decisions affecting our executive officers. However, management also plays a role in the determination of executive compensation levels. At the beginning of each year, at the request of the compensation committee, management proposes certain corporate and executive performance objectives for executive management. Management also participates in the discussion of peer companies to be used to benchmark named executive officers’ compensation. All management recommendations are reviewed and modified as necessary by the compensation committee, and approved by the compensation committee. The compensation committee meets regularly in executive session without management present.

Compensation Philosophy

In order to recruit and retain the most qualified and competent individuals as senior executives, we strive to maintain a compensation program that is competitive in our market and with respect to the general profession of our executives. We remain committed to hiring and retaining qualified, motivated employees at all levels within the organization while ensuring that all forms of compensation are aligned with business needs. The purpose of our compensation program is to reward exceptional organizational and individual performance. Our compensation system is designed to support the successful attainment of our vision, values and business objectives.

The following compensation objectives are considered in setting the compensation components for our senior executives:


	•	Attract and retain key executives responsible not only for our continued growth and profitability, but also for ensuring proper corporate governance and carrying out the goals and plans of our company;

	•	Motivate management to enhance long-term stockholder value and to align our executives’ interests with those of our stockholders;

	•	Correlate a portion of management’s compensation to measurable performance, including specific financial and operating goals;

	•	Evaluate and rate performance relative to the existing market conditions during the measurement period; and

	•	Set compensation and incentive levels that reflect competitive market practices.

The principal components of our executive compensation program are base salary, annual incentive bonuses and long-term incentive awards. We blend these elements in order to formulate compensation packages which provide competitive pay, reward the achievement of financial, operational and strategic objectives on a short- and long-term basis, and align the interests of our executive officers and other senior personnel with those of our stockholders.

We have traditionally utilized stock incentives as a means to align the interests of our management with the interests of our shareholders and motivate our management to enhance shareholder value. Stock issuances to-date have been designed to serve as both short-term rewards and long-term incentives. As a result, each of our named executive officers holds a significant number of shares of our outstanding common stock.

Employment Agreements

All employees, including the officers named in the Summary Compensation table below, have entered into written employment agreements with our company. All such agreements provide that year-end cash bonuses are at the discretion of the compensation committee or board of directors, to be determined according to our achievement of specified predetermined and mutually agreed upon performance objectives each year.

Elements of Compensation

The total compensation and benefits program for our senior executives generally consists of the following components:


	•	base salaries;

	•	annual bonus incentive plan;

	•	discretionary bonuses;


	•	long-term equity-based incentive compensation;

	•	retirement, health and welfare benefits;

	•	perquisites; and

	•	severance payments/change of control.

Base Salaries

We provide base salaries to compensate our senior executives and other employees for services performed during the fiscal year. This provides a level of financial certainty and stability in an industry with historical volatility and cyclicality. The base salaries are designed to reflect the experience, education, responsibilities and contribution of the individual executive officers. This form of compensation is eligible for annual merit increases, and is initially established for each executive through individual negotiation and is reflected in his or her employment agreement. Thereafter, salaries are reviewed annually, based on a number of factors, both quantitative, including detailed organizational and competitive analyses, and qualitative, including the compensation committee’s perception of the executive’s experience, performance and contribution to our business objectives and corporate values.

At the request of management, effective January 1, 2011, Mr. Reger and Mr. Gilbertson elected to not receive any cash compensation, meaning they will be compensated solely through incentive stock grants on a going-forward basis. Receiving only stock compensation is intended to further align our executive officers’ personal performance and success with interests and success of our shareholders.

Annual Bonus Incentive Plan

The annual stock bonus incentive plan provides variable compensation earned only when established performance goals are achieved. It is designed to reward the plan participants, including the named executive officers, who have achieved certain corporate and executive performance objectives and have contributed to the achievement of certain objectives of our company.

Under this compensation program, each executive has the opportunity to earn a incentive compensation bonus up to a maximum of 100% of base salary, based on the achievement of pre-determined operating and financial performance measures and other performance objectives established by the compensation committee. The goals include a financial target and other targets.

Discretionary Bonuses

In addition to bonuses under the incentive plan discussed above, the compensation committee may also approve the payment of discretionary bonuses to officers and other employees in recognition of significant achievements.

2010 Bonuses

Near the end of 2010, the compensation committee met on multiple occasions to consider the performance of our named executive officers and make year-end compensation decisions. In evaluating the performance of our named executive officers, the committee primarily focused on the accomplishments and overall performance of our company during 2010. Based primarily on the growth of our company between March 2010 and the end of 2010, the compensation committee revised the applicable group of peer companies and used publicly available data to compare the compounded annual growth rate of those peers to that of our company to inform the committee in connection with the determination of 2010 bonuses and year-end compensation decisions. The committee evaluated the compounded annual growth rate of our company to a group of peer companies that included Kodiak Oil and Gas, Carrizo Oil & Gas, Inc., Swift Energy Co., Energy XXI (Bermuda) Limited, Oasis Oil and Gas Corporation, Bill Barrett Corporation, Berry Oil, Rosetta Resources, Inc., Brigham Exploration Company, St. Mary’s County Oil Companies, Whiting Petroleum Corporation and Continental Oil and Gas. Notable accomplishments in 2010 taken into account by the compensation committee included the closing of a $100 million credit facility with Macquarie Bank Limited (“Macquarie”) the raising of over $280 million in equity capital at successively accretive levels, the substantial increase in production and revenues from 2009 to 2010, the efficient expansion of our acreage position throughout 2010 and the realization of more than a 125% stock appreciation during 2010.

We did not pay any cash bonuses in 2010. All bonus compensation during 2010 was provided through the issuance of shares of our common stock under our 2009 Equity Incentive Plan. On November 30, 2010, in recognition of the contributions by the named executive officers and the accomplishments of our company during 2010, the compensation committee approved the issuance of 43,326 shares of fully vested common stock to each of Mr. Reger and Mr. Gilbertson. The grant date fair value of the shares was $989,999 to each of Mr. Reger and Mr. Gilbertson. The compensation committee also approved the issuance of 30,854 shares to Mr. Sankovitz, having a grant date fair value of $705,014, and 20,569 shares to Mr. Winter, having a grant date fair value of $470,002. The total bonus amount for each executive officer was determined by the compensation committee on a post hoc basis based on the compensation committee’s assessment of Mr. Reger, Mr. Gilbertson, Mr. Sankovitz and Mr. Winter’s contributions to our accomplishments noted below under the heading “Year-End Compensation Decisions.”

Year-End Compensation Decisions

The compensation committee translated its qualitative assessment of our company’s notable accomplishments in 2010, as disclosed under the heading “2010 Bonuses,” into share issuance amounts by evaluating the performance of our named executive officers and the accomplishments and overall performance of our company during the 2010 fiscal year. Based on these accomplishments and the growth rate of our company compared to peer companies, the compensation committee granted bonuses to our named executive officers equal to three times the base salaries of Messrs. Reger, Gilbertson and Sankovitz and twice the base salary of Mr. Winter. The shares issued to our named executive officers in connection with their 2010 year-end bonuses were determined by dividing those amounts by the market value of our common stock on the date the resulting bonus shares were issued. The grant date fair value of the bonus shares is disclosed under the heading “2010 Bonuses.”

In order to maximize the incentive attributes of the total compensation of our chief executive officer and president, the compensation committee granted 162,000 shares of restricted stock to each of Mr. Reger and Mr. Gilbertson on January 14, 2011, vesting over a period of three years. The compensation committee determined to utilize a multi-year vesting schedule to create both short term and long term incentive goals and align such vesting with our goal of managing lease expirations over the ensuing years. As such, 6,500 shares vested immediately upon grant and the remaining 155,500 shares vests in 11 equal installments of 6,500 shares on the first of every month starting February 1, 2011. Commencing January 1, 2012, an additional 3,500 shares shall vest per month on the first day of each succeeding calendar month until all shares granted to Messrs. Reger and Gilbertson are fully vested.

Long-Term Equity-Based Incentive Compensation

The purpose of our long-term incentive compensation is to align the interests of our executives with those of our stockholders. Since equity awards may vest and grow in value over time, this component of our compensation plan is designed to provide incentives to reward performance over a sustained period.

Restricted stock awards represent awards of actual shares of our common stock that include vesting provisions which are contingent upon continued employment and occasionally achievement of certain performance objectives. We believe that awards of restricted stock provide a significant incentive for executives to achieve and maintain high levels of performance over multi-year periods, and strengthen the connection between executive and stockholder interests. We believe that restricted shares are a powerful tool for helping us retain executive talent. The higher value of a share of restricted stock in comparison to a stock option allows us to issue fewer total shares in order to arrive at a competitive total long-term incentive award value. Furthermore, we believe that the use of restricted stock reflects competitive practice among other exploration and production companies with whom we compete for executive talent.

2010 Long Term Equity Incentive

Based on the analysis performed by BDO, on March 17, 2010, the compensation committee approved the issuance of 250,000 shares of common stock to each of our named executive officers vesting variably over four years. The shares vest in quarterly installments to the extent of 20% in year one, 25% in year two and three, and 30% in year four contingent on continued employment and achievement of certain predetermined performance objectives. The one-time grant was implemented to recognize the increase in responsibilities assumed by Mr. Winter upon promotion to chief financial officer and Mr. Sankovitz upon promotion to chief operating officer, and the continued contributions of Mr. Reger and Mr. Gilbertson. Such grants were intended as a one-time grant made to significantly increase each executive officer’s personal stake in our company, thereby further aligning their interests with those of our shareholders. In addition, the four year vesting period will provide our executive officers with a strong incentive to remain employed with our company for the long-term. The four year variable vesting schedule also creates both short term and long term incentive goals and aligns such vesting with our goal of managing lease expirations over the ensuing years.

Retirement, Health and Welfare Benefits

We offer a variety of retirement, health and welfare programs to all eligible employees. Under the terms of their employment agreements, the named executive officers are eligible for the same broad-based benefit programs on the same basis as the rest of our employees. Our health and welfare programs include medical, pharmacy, dental and long and short term disability.

We maintain a 401(k) plan for our employees. Under the 401(k) plan, eligible employees may elect to contribute up to 6% of their eligible compensation on a pre-tax basis in accordance with the limitations imposed under the Internal Revenue Code of 1986, as amended, or the Code. We also provide a match contribution equal to 100% of an eligible employee’s deferral contribution, up to 6% of the employee’s earnings up to $16,500.

Perquisites

Additional perquisites paid for named executive officers in 2010 include personal use of company-leased vehicles, reimbursement of certain approved personal travel and entertainment expenses, and tax gross ups. Maximum combined perquisite dollar limits exist for all named executive officers on an annual basis. Our costs associated with providing these benefits for named executive officers in 2010 are reflected in the Summary Compensation Table and related disclosures below.

Effective January 1, 2011, tax gross ups have been eliminated for all named executive officers.

Severance Payments/Change of Control

We have employment agreements in place with each of the named executive officers providing for lump sum severance compensation if the executive’s employment is terminated for a variety of reasons, including a change of control of our company. We have provided more information about these benefits, along with estimates of the value under various circumstances, in the Summary Compensation Table and related disclosures below.

COMPENSATION COMMITTEE REPORT

Compensation Committee Activities

The compensation committee of our board consists of three independent directors. As the compensation committee, we authorize and evaluate programs and, where appropriate, establish relevant performance criteria to determine management compensation. Our compensation committee charter grants the compensation committee full authority to review and approve annual base salary and incentive compensation levels, employment agreements and benefits of executive officers and other key employees. We intend to adopt performance criteria to measure the performance of our executive management and determine the appropriateness of awarding year-end cash bonuses based on performance company performance.

Review of Compensation Discussion and Analysis

The compensation committee has reviewed and discussed the compensation discussion and analysis presented on the preceding pages. Based on its review and discussions, the compensation committee recommended to the board of directors that the compensation discussion and analysis be included in this proxy statement.

The name of each person who serves as a member of our compensation committee is set forth below.


Loren J. O’Toole	Robert Grabb	Lisa Meier

Risks Arising from Compensation Policies and Practices

In connection with year-end procedures for 2010, our management recently conducted an evaluation of the risks arising from our company-wide compensation policies and practices with respect to employees. Management prepared a report and analysis of our compensation policies and practices and concluded that they do not create risks that are reasonably likely to have a material adverse effect on our company. In connection with its risk oversight role, our compensation committee reviewed management’s analysis and conclusions.

Summary Compensation Table

The table below shows compensation for our named executive officers for services in all capacities to our company during fiscal years 2008, 2009 and 2010. Compensation, as reflected in this table and the tables which follow, is presented on the basis of rules of the SEC and does not, in the case of certain stock-based awards or accruals, necessarily represent the amount of compensation realized or which may be realized in the future. For more information regarding our salary policies and executive compensation plans, please review the information under the caption “Compensation Discussion and Analysis.”


Name and Principal Position(1)	Year		Salary ($)		Bonus ($)(2)		Stock Awards ($)(3)			Non-Equity Incentive Plan Compensation ($)(4)		All Other Compensation ($)(5)(6)		Total Compensation ($)
Michael L. Reger		2008		185,000		100,000		—			370,000		155,833		810,833
Chief Executive Officer and Chairman of the Board		2009		285,000		570,000		1,455,000	₍₇₎		—		50,186		2,360,186
		2010		330,000		—		4,312,499	₍₈₎		—		84,973		4,727,472

Ryan R. Gilbertson		2008		185,000		100,000		—			370,000		156,964		811,964
President		2009		285,000		570,000		1,455,000	₍₉₎		—		58,782		2,368,782
		2010		330,000		—		4,312,499	₍₁₀₎		—		71,405		4,713,904

Chad D. Winter		2008		105,000		—		—			—		677		105,677
Chief Financial Officer		2009		155,000		—		441,750	₍₁₁₎		—		34,478		631,228
		2010		235,000		—		3,792,502	₍₁₂₎		—		47,502		4,075,004

James R. Sankovitz		2008		100,000		—		140,500	₍₁₃₎		—		1,802		242,302
Chief Operating Officer, General Counsel & Secretary		2009		155,000		—		441,750	₍₁₄₎		—		39,613		636,363
		2010		235,000		—		4,027,514	₍₁₅₎		—		66,723		4,329,237


(1)	Mr. Reger joined our company as Chief Executive Officer, Chairman of the Board and Secretary and Mr. Gilbertson joined us as Chief Financial Officer and a director on March 20, 2007. Mr. Winter joined our company in November 2007 and Mr. Sankovitz joined our company in March 2008.
(2)	The amounts reported for Messrs. Reger and Gilbertson represent $100,000 signing bonuses upon execution of employment agreements in 2008 and $570,000 year-end cash bonuses in 2009.
(3)	Valuation of awards based on the grant date fair value of those awards computed in accordance with FASB ASC Topic 718 utilizing assumptions discussed in note 6 to our financial statements for the fiscal year ended December 31, 2010 included in our Annual Report on Form 10-K for fiscal year 2010.
(4)	For 2008, the amounts reported for Messrs. Reger and Gilbertson include a $370,000 year-end bonus based upon achievement of performance objectives and approved by the compensation committee but paid through issuance of promissory notes in lieu of cash bonus.
(5)	For 2008, the amounts reported for Messrs. Reger and Gilbertson include $153,735 accrued by our company as an additional bonus to pay tax obligations associated with year-end bonuses in consideration of their willingness to accept such bonuses in the form of unsecured notes rather than cash.
(6)	The amounts reported consist of the following for 2009:


Form of All Other Compensation	Michael L. Reger		Ryan R. Gilbertson		Chad D. Winter		James R. Sankovitz
Personal use of company-leased vehicles ($)		7,202		7,032		9,113		11,977
401(k) contributions by the Company ($)		16,500		16,500		16,500		16,500
Reimbursement of personal travel and entertainment expenses ($)		10,698		5,274		1,445		2,876
Tax Gross-ups ($)		15,786		29,976		7,420		8,260
Total ($)		50,186		58,782		34,478		39,613


	The amounts reported consist of the following for 2010.


Form of All Other Compensation	Michael L. Reger		Ryan R. Gilbertson		Chad D. Winter		James R. Sankovitz
Personal use of company-leased vehicles ($)		10,731		10,673		9,023		11,176
401(k) contributions by the Company ($)		16,500		16,500		16,500		16,500
Reimbursement of personal travel and entertainment expenses ($)		21,936		20,039		3,759		17,128
Tax Gross-ups ($)		35,806		24,193		18,220		21,919
Total ($)		84,973		71,405		47,502		66,723


	Our compensation committee has determined to eliminate all tax gross ups going forward commencing January 1, 2011.
(7)	Reflects the grant date fair value of 50,000 shares of common stock and 100,000 shares of restricted common stock granted to Mr. Reger on December 7, 2009, in connection with his 2009 year-end bonus compensation.
(8)	Includes (i) $3,322,500, which is the grant date fair value of 12,500 shares of common stock and 237,500 shares of restricted common stock granted to Mr. Reger on March 17, 2010, in connection with his long-term incentive stock grant and (ii) $989,999 which is the grant date fair value of 43,326 shares of common stock granted to Mr. Reger on November 30, 2010, in connection with his 2010 year-end bonus compensation.
(9)	Reflects the grant date fair value of 50,000 shares of common stock and 100,000 shares of restricted common stock granted to Mr. Gilbertson on December 7, 2009, in connection with his 2009 year-end bonus compensation.
(10)	Includes (i) $3,322,500, which is the grant date fair value of 12,500 shares of common stock and 237,500 shares of restricted common stock granted to Mr. Gilbertson on March 17, 2010, in connection with his long-term incentive stock grant and (ii) $989,999 which is the grant date fair value of 43,326 shares of common stock granted to Mr. Gilbertson on November 30, 2010, in connection with his 2010 year-end bonus compensation.
(11)	Includes (i) $213,000, which is the grant date fair value of 45,000 shares of common stock and 30,000 shares of restricted common stock granted to Mr. Winter on February 23, 2009, in connection with a stock bonus and (ii) $228,750, which is the grant date fair value of 25,000 shares of common stock granted to Mr. Winter on November 30, 2009, in connection with his 2009 year-end bonus compensation.
(12)	Includes (i) $3,322,500, which is the grant date fair value of 12,500 shares of common stock and 237,500 shares of restricted common stock granted to Mr. Winter on March 17, 2010, in connection with his long-term incentive stock grant and (ii) $470,002 which is the grant date fair value of 20,569 shares of common stock granted to Mr. Winter on November 30, 2010, in connection with his 2010 year-end bonus compensation.
(13)	Reflects the grant date fair value of 20,000 shares of restricted common stock granted to Mr. Sankovitz upon the commencement of his employment in March 2008.
(14)	Includes (i) $213,000, which is the grant date fair value of 45,000 shares of common stock and 30,000 shares of restricted common stock granted to Mr. Sankovitz on February 23, 2009, in connection with a stock bonus and (ii) $228,750, which is the grant date fair value of 25,000 shares of common stock granted to Mr. Sankovitz on November 30, 2009, in connection with his 2009 year-end bonus compensation.
(15)	Includes (i) $3,322,500, which is the grant date fair value of 12,500 shares of common stock and 237,500 shares of restricted common stock granted to Mr. Sankovitz on March 17, 2010, in connection with his long-term incentive stock grant and (ii) $705,014 which is the grant date fair value of 30,854 shares of common stock granted to Mr. Sankovitz on November 30, 2010, in connection with his 2010 year-end bonus compensation.

Grants of Plan-Based Awards

The following table sets forth grants of plan-based awards during the year ended December 31, 2010, which consisted solely of grants of common stock and restricted common stock. All grants were made pursuant to the 2009 Equity Incentive Plan.

Name

Grant Date

Compensation
Committee
Approval Date

Number of Shares
of Common Stock

Grant Date
Fair Value of
Stock Awards ($)

Michael L. Reger

3/17/2010

250,000

3,322,500

11/30/2010

43,326

989,999

Ryan R. Gilbertson

3/17/2010

250,000

3,322,500

11/30/2010

43,326

989,999

Chad D. Winter

3/17/2010

250,000

3,322,500

11/30/2010

20,569

470,002

James R. Sankovitz

3/17/2010

250,000

3,322,500

11/30/2010

30,854

705,014

Outstanding Equity Awards

The following table sets forth the outstanding equity awards to our named executive officers as of December 31, 2010.


	Stock Awards
Name	Number of Shares That Had Not Vested			Market Value of Shares That Had Not Vested(1)
Michael L. Reger		262,496	₍₂₎	$	7,142,516
Ryan R. Gilbertson		262,496	₍₃₎	$	7,142,516
Chad D. Winter		227,500	₍₄₎	$	6,190,275
James R. Sankovitz		227,500	₍₅₎	$	6,190,275


(1)	The values in this column are based on the $27.21 closing price of our common stock on the NYSE AMEX Equities Market on December 31, 2010.
(2)	Consists of restricted common stock granted to Mr. Reger on December 7, 2009, 4,167 shares will vest on the first day of each month from January 2011 through November 2011 and the final 4,159 shares will vest on December 1, 2011. The restricted common stock granted to Mr. Reger on March 17, 2010, 12,500 shares will vest on January 1, 2011, 15,625 shares will vest on April 1, 2011, July 1, 2011, October 1, 2011, January 1, 2012, April 1, 2012, July 1, 2012, October 1, 2012 and January 1, 2013 and 18,750 shares will vest on April 1, 2013, July 1, 2013, October 1, 2013 and January 1, 2014.
(3)	Consists of restricted common stock granted to Mr. Gilbertson on December 7, 2009. 4,167 shares will vest on the first day of each month from January 2011 through November 2011 and the final 4,159 shares will vest on December 1, 2011. The restricted common stock granted to Mr., Gilbertson on March 17, 2010, 12,500 shares will vest on January 1, 2011, 15,625 shares will vest on April 1, 2011, July 1, 2011, October 1, 2011, January 1, 2012, April 1, 2012, July 1, 2012, October 1, 2012 and January 1, 2013 and 18,750 shares will vest on April 1, 2013, July 1, 2013, October 1, 2013 and January 1, 2014.
(4)	Consists of restricted common stock granted to Mr. Winter on February 23, 2009, 15,000 shares will vest on January 1, 2011 and restricted common stock granted to Mr., Winter on March 17, 2010, 12,500 shares will vest on January 1, 2011, 15,625 shares will vest on April 1, 2011, July 1, 2011, October 1, 2011, January 1, 2012, April 1, 2012, July 1, 2012, October 1, 2012 and January 1, 2013 and 18,750 shares will vest on April 1, 2013, July 1, 2013, October 1, 2013 and January 1, 2014.
(5)	Consists of restricted common stock granted to Mr. Sankovitz on February 23, 2009, 15,000 shares will vest on January 1, 2011 and restricted common stock granted to Mr., Sankovitz on March 17, 2010, 12,500 shares will vest on January 1, 2011, 15,625 shares will vest on April 1, 2011, July 1, 2011, October 1, 2011, January 1, 2012, April 1, 2012, July 1, 2012, October 1, 2012 and January 1, 2013 and 18,750 shares will vest on April 1, 2013, July 1, 2013, October 1, 2013 and January 1, 2014.

Option Exercises and Stock Vested

Our named executive officers did not hold or exercise any stock options during the year ended December 31, 2010. The table below sets forth the number of shares of common stock acquired on vesting by our named executive officers during the year ended December 31, 2010.


	Stock Awards
Name	Number of Shares Acquired on Vesting	Value Realized on Vesting
Michael L. Reger	130,830		$	2,319,103	₍₁₎
Ryan R. Gilbertson	130,830		$	2,319,103	₍₂₎
Chad D. Winter	58,069		$	1,021,127	₍₃₎
James R. Sankovitz	68,354		$	1,256,139	₍₄₎


(1)	Mr. Reger had 4,167 shares of restricted stock vest on the first day of each month in 2010 (50,004 total). The average closing price of our common stock on the NYSE AMEX Equities Market on such dates was $15.56. Mr. Reger received a grant of 12,500 shares of fully vested common stock on March 17, 2010. The closing price of our common stock on the NYSE AMEX Equities Market in such date was $13.29. Mr. Reger had 12,500 shares of restricted stock vest on July 1, 2010 and October 1, 2010. The closing price of our common stock on the NYSE AMEX Equities Market on such dates was $12.83 and $17.97, respectively. Mr. Reger received a grant of 43,326 shares of fully vested common stock on November 30, 2010. The closing price of our common stock on the NYSE AMEX Equities Market on such date was $22.85.
(2)	Mr. Gilbertson had 4,167 shares of restricted stock vest on the first day of each month in 2010 (50,004 total). The average closing price of our common stock on the NYSE AMEX Equities Market on such dates was $15.56. Mr. Gilbertson received a grant of 12,500 shares of fully vested common stock on March 17, 2010. The closing price of our common stock on the NYSE AMEX Equities Market in such date was $13.29. Mr. Gilbertson had 12,500 shares of restricted stock vest on July 1, 2010 and October 1, 2010. The closing price of our common stock on the NYSE AMEX Equities Market on such dates was $12.83 and $17.97, respectively. Mr. Gilbertson received a grant of 43,326 shares of fully vested common stock on November 30, 2010. The closing price of our common stock on the NYSE AMEX Equities Market on such date was $22.85.


(3)	Mr. Winter received a grant of 12,500 shares of fully vested common stock on March 17, 2010. The closing price of our common stock on the NYSE AMEX Equities Market in such date was $13.29. Mr. Winter had 12,500 shares of restricted stock vest on July 1, 2010 and October 1, 2010. The closing price of our common stock on the NYSE AMEX Equities Market on such dates was $12.83 and $17.97, respectively. Mr. Winter received a grant of 20,569 shares of fully vested common stock on November 30, 2010. The closing price of our common stock on the NYSE AMEX Equities Market on such date was $22.85.
(4)	Mr. Sankovitz received a grant of 12,500 shares of fully vested common stock on March 17, 2010. The closing price of our common stock on the NYSE AMEX Equities Market in such date was $13.29. Mr. Sankovitz had 12,500 shares of restricted stock vest on July 1, 2010 and October 1, 2010. The closing price of our common stock on the NYSE AMEX Equities Market on such dates was $12.83 and $17.97, respectively. Mr. Sankovitz received a grant of 30,854 shares of fully vested common stock on November 30, 2010. The closing price of our common stock on the NYSE AMEX Equities Market on such date was $22.85.

Defined Benefit Plans

We did not maintain any defined benefit plans during the year ended December 31, 2010.

Potential Payments upon Termination or Change in Control

In January 2008, we entered into employment agreements with Mr. Reger and Mr. Gilbertson covering their service as our Chief Executive Officer and Chief Financial Officer, respectively. In November 2007 and March 2008, we entered into employment agreements with Mr. Winter and Mr. Sankovitz, respectively, as a condition to their employment with our company. On January 30, 2009, our board of directors and compensation committee approved certain amendments to all employment agreements, which were effected through amended and restated employment agreements. In March 2010, Mr. Winter and Mr. Sankovitz were promoted to executive officer positions with our company and in connection therewith entered into new employment agreements. On January 14, 2011, the compensation committee approved certain additional amendments to the employment agreements between our company and each of Mr. Reger and Mr. Gilbertson.

General Employment Agreement Provisions

The current employment agreements entitle Messrs. Winter and Sankovitz to each receive an annual base salary as determined by our compensation committee, but which shall increase each year a minimum of 4% over the prior year’s annual salary. All officers are eligible to receive bonus compensation at the discretion of our compensation committee or board of directors based upon meeting or exceeding established performance objectives. The employment agreements also contain provisions prohibiting our named executive officers from competing with our company or soliciting any employees of our company for a period of one year following termination of their employment in the event either officer terminates his employment with our company.

The current employment agreements have a three-year term commencing January 30, 2009 for Messrs. Reger and Gilbertson and March 25, 2010 for Messrs. Winter and Sankovitz, which term automatically renews for an additional three-year term each year unless otherwise terminated by either our company or the employee. Notwithstanding the specified term, each employee’s employment with our company is entirely “at-will,” meaning that either the employee or our company may terminate such employment relationship at any time for any reason or for no reason at all, subject to the provisions of the then-applicable employment agreements.

Change-in-Control and Similar Provisions

The Compensation Committee utilized change of control provisions that were previously approved by the Company’s Board of Directors as part of the Company’s executive employment agreements. These provisions initially were suggested by the Company’s outside legal counsel at the time the Company entered into employment agreements with Mr. Reger and Mr. Gilbertson based on common practices of similarly situated companies, and have been utilized consistently by the Company and the Compensation Committee since that time.

The current employment agreements of each named executive officer contain change-in-control provisions entitling the employees to certain payments under specified circumstances. A “change-in-control” is defined as any one or more of the following:


	•	The consummation of a reorganization, merger, share exchange, consolidation or similar transaction, or the sale or disposition of all or substantially all of the assets of our company, unless, in any case, the persons beneficially owning the voting securities of our company immediately before that transaction beneficially own, directly or indirectly, immediately after the transaction, at least 75% of the voting securities of our company or any other corporation or other entity resulting from or surviving the transaction in substantially the same proportion as their respective ownership of the voting securities of our company immediately prior to the transaction;


	•	Individuals who constitute the incumbent board of directors cease for any reason to constitute at least a majority of the board of directors; or

	•	Our shareholders approve a complete liquidation or dissolution of our company.

Upon a change-in-control of our company, each employee’s employment agreement will immediately cease and our employees will be entitled to certain specified compensation.

In the event of a change-in-control, upon the earlier to occur of their death or six months following the “change in control” we must pay Messrs. Winter and Sankovitz a lump sum payment equal to twice their then-applicable annual salary in lieu of any and all other benefits and compensation to which they otherwise would be entitled. Effective January 14, 2011, we amended the employment agreements of Messrs. Reger and Gilbertson. The agreements were amended to (i) extend the period of applicability for the non-competition and non-solicitation provisions in the original agreements from one to three years following termination of Mr. Reger’s or Mr. Gilbertson’s employment with our company and (ii) amend and restate the change in control provision under the original agreements to allow for a lump sum of $2.5 million to be paid to Messrs. Reger and Gilbertson in the event of a change in control of our company. Under their respective employment agreements, all of the named executive officers also are entitled to the pre-payment of the remaining lease term of their company vehicle and use of such vehicle through the remaining lease term of such vehicle, along with a lump sum payment of the estimated insurance premiums for such vehicle through the remaining lease terms upon a change-in-control.

In addition to the cash payments referenced above, upon any change-in-control our company or its successor must pay and/or issue (as appropriate) to both Messrs. Winter and Sankovitz that amount of cash and/or that number of shares of our common stock or shares of capital stock or ownership interests of any other entity which they would have been entitled to receive in connection with the change-in-control had they owned an aggregate of 30,000 fully-paid and non-assessable shares of our common stock prior to the change-in-control.

Estimated Payments to Named Executive Officers

The compensation amounts below are estimates of the amounts that would have become payable to each named executive officer employed by our company on December 31, 2010, the last business day of our most recent fiscal year, if his employment had terminated on such date. The calculations for severance in connection with a change in control assume that the change in control and severance both occurred on the last business day of 2010.

Assuming a change-in-control had occurred as of December 31, 2010, Messrs. Reger and Gilbertson each would have been entitled to receive a lump sum cash payment of $660,000 and, assuming then-applicable base salaries, each of Messrs. Winter and Sankovitz would have been entitled to receive a lump sum cash payment of $470,000. In addition, Messrs. Reger and Gilbertson each would have been entitled to payment of approximately $50,500 toward their vehicle lease and related insurance, Mr. Winter would have been entitled to a payment of approximately $12,000 toward his vehicle lease and related insurance and Mr. Sankovitz would have been entitled to a payment of approximately $48,000 toward his vehicle lease and related insurance. The restricted stock award agreements covering unvested stock issued to each of our executive officers also provide that any unvested shares automatically vest upon a change-in-control. At December 31, 2010, the value of restricted stock held by each of Mr. Reger and Mr. Gilbertson and vesting upon a change-in-control would have approximated $7,142,516. At December 31, 2010, the value of restricted stock held by each of Mr. Winter and Mr. Sankovitz and vesting upon a change-in-control would have approximated $6,190,275.

Non-Employee Director Compensation

Director compensation elements are designed to:


	•	Ensure alignment with long-term shareholder interests;

	•	Ensure we can attract and retain outstanding director candidates;

	•	Recognize the substantial time commitments necessary to oversee the affairs of our company; and

	•	Support the independence of thought and action expected of directors.

Non-employee director compensation levels are reviewed by the compensation committee each year, and resulting recommendations are presented to the full board for approval. Our employees receive no additional pay for serving as directors.

Non-employee directors receive compensation consisting of equity in the form of restricted stock and cash for committee service. A significant portion of director compensation is paid in restricted stock to align director compensation with the long-term interests of shareholders. Non-employee directors are also reimbursed for reasonable expenses incurred to attend board meetings or other functions relating to their responsibilities as a director.

On November 1, 2007, each of our non-employee directors received an option to purchase 100,000 shares of common stock pursuant to our 2006 Incentive Stock Option Plan. The options were fully vested at the time of grant and are exercisable at $5.18 per share, which represents the fair market value of our common stock on the date of grant, calculated based on the average close/last trade price of our common stock reported for the five highest volume trading days during the 30 day trading period ending on the last trading day preceding the date of grant (rounded to the nearest penny).

On December 7, 2009, each of our non-employee directors received a grant of 25,000 shares of common stock pursuant to our 2009 Equity Incentive Plan, of which 8,334 shares were fully vested upon issuance and the remaining 16,666 are restricted shares that vest in approximately equal installments on the first day of each month from January 2010 through December 2011.

Beginning in 2010, the chair of the audit committee received an additional $25,000 per year and each audit committee member other than the chair received an additional $5,000 for their service on an annual basis. The chair of the compensation committee received an additional $20,000 per year and each compensation committee member other than the chair received an additional $5,000 for their service on an annual basis. The chair of the nominating committee received an additional $7,500 per year and each nominating committee member other than the chair received an additional $2,500 for their service on an annual basis.

The following table contains compensation information for our non-employee directors for the year ended December 31, 2010. Our non-employee directors did not receive any cash compensation prior to 2010.


Name	Fees Earned or Paid in Cash ($)		Stock Awards ($)(1)(2)		Option Awards ($)(3)		Total ($)
Robert Grabb		17,500		228,500		—		246,000
Jack E. King		2,500		228,500		—		231,000
Lisa Meier		45,000		228,500		—		273,500
Loren J. O’Toole		12,500		228,500		—		241,000
Carter Stewart		—		228,500		—		228,500



(1)	Each non-employee director received a grant of 10,000 shares of restricted common stock, on November 30, 2010. Valuation of awards based on the grant date fair value of those awards computed in accordance with FASB ASC Topic 718 utilizing assumptions discussed in note 6 to our consolidated financial statements for the fiscal year ended December 31, 2010.
(2)	As of December 31, 2010, each non-employee director held 18,326 shares of unvested restricted common stock.
(3)	As of December 31, 2010, Mr. King and Mr. O’Toole each held stock options to purchase 100,000 shares of common stock and Ms. Meier held stock options to purchase 65,963 shares of common stock at $5.18 per share. Mr. Grabb and Mr. Stewart held no stock options.

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

As an oil and gas exploration company, our business strategy is to identify and exploit resources in and adjacent to existing or indicated producing areas that can be quickly developed and put in production at low cost. We are focused on low overhead and, thus, have relied upon various relationships with third-parties that assist us in identifying and acquiring property in the most exciting new plays in a nimble and efficient fashion. As a consequence, we have entered into and may in the future enter into, certain transactions and arrangements with parties that have a direct or indirect relationship with one or more members of our management or board of directors.

Related Person Transaction Review Policy

Our audit committee charter and the NYSE Amex company guide require that our audit committee review and approve all material transactions between our company and its directors, officers and 5% or greater shareholders, as well as all material transactions between our company and any relative or affiliate of any of the foregoing. In reviewing such transactions, the Audit Committee generally utilizes third-party data to assist in evaluating whether the specific terms and provisions of each individual transaction are no less favorable to us than we could obtain from unaffiliated third parties. The Audit Committee historically has relied upon data from state and federal lease auctions to support the appropriateness of prices paid to any related party in connection with any leasehold acquisition. We anticipate that our audit committee will review and approve or ratify future transactions involving any executive officer, director, 5% or greater shareholder or any relative or affiliate of any of the foregoing.

Transactions with Other Companies

We have purchased leasehold interests from South Fork Exploration, LLC (“SFE”) pursuant to a continuous lease program that covers specific agreed upon sections of townships and ranges in Burke, Divide, and Mountrail Counties of North Dakota where SFE previously acquired leasehold interests on our behalf and is authorized to continue to acquire additional acreage within the proximity of the originally-acquired leases. This program differs from other arrangements where we may purchase specific leases in one-time, single closing transactions. In 2010, we paid a total of $5,000 related to previously acquired leasehold interests. Because each lessor separately negotiates its own desired royalty, SFE’s over-riding royalty interest varies from lease to lease. We are receiving a net revenue interest ranging from 80.25% to 82.5% net revenue interest in the acquired leases, which is net of royalties and overriding royalties. SFE’s president is J.R. Reger, the brother of our Chief Executive Officer, Michael Reger. J.R. Reger is also a shareholder of our company.

We have also purchased leasehold interests from Montana Oil Properties (“MOP”). In July 2010, we paid MOP a total of $269,821 for leases and reimbursement costs pertaining to two separate wells in Mountrail County, North Dakota. MOP is controlled by Mr. Tom Ryan and Mr. Steven Reger, both are relatives of our Chief Executive Officer, Michael Reger.

We have also purchased leasehold interests from Gallatin Resources, LLC (“Gallatin”). In 2008, we purchased leasehold interests from Gallatin for a total consideration of approximately $22,109. In 2009, we paid Gallatin a total of $22,223 related to previously acquired leasehold interests. In 2010, we paid Gallatin a total of $15,822 related to a previously acquired leasehold interests. Carter Stewart, one of our directors, owns a 25% interest in Gallatin. Legal counsel for Gallatin informed us that Mr. Stewart does not have the power to control Gallatin Resources because each member of Gallatin has the right to vote on matters in proportion to their respective membership interest in the company and company matters are determined by a vote of the holders of a majority of membership interests. Further, Mr. Stewart is neither an officer nor a director of Gallatin. As such, Mr. Stewart does not have the ability to individually control company decisions for Gallatin.

On November 17, 2009, the audit committee approved the opening of an investment account with Morgan Stanley Smith Barney LLC for management of a portion of our excess cash. This account will be managed by Kathleen Gilbertson, a financial advisor with that firm who is the sister of our president and director, Ryan Gilbertson. Depending on liquidity needs, we expect to invest approximately $50 million to $100 million in this investment account and Kathleen Gilbertson’s personal interest in 2010 was approximately $24,000.

Transactions between Our Company and Our Directors or Officers

On January 30, 2009, our compensation committee and audit committee approved the issuance of non-negotiable, unsecured subordinated promissory notes in the principal amount of $370,000 to both Mr. Reger and Mr. Gilbertson in lieu of paying cash bonuses earned in 2008. Final payment of the notes occurred in December, 2010.

Except as disclosed above, we had no transactions during 2010 and none are currently proposed, in which we were a participant and in which any related person had a direct or indirect material interest.

Board Committees

The board of directors has standing audit, compensation and nominating committees. As of May 2, 2011, all three committees consisted solely of independent directors. The table below shows the current membership of the committees and identifies our independent directors.

Name

Audit Committee

Compensation
Committee

Nominating
Committee

Independent
Directors

Ryan R. Gilbertson

Robert Grabb

ü*

Jack King

Lisa Meier

ü*

Loren J. O’Toole

Michael L. Reger

Carter Stewart

* Denotes committee chairman. Ms. Meier also serves as our lead independent director.

Director Independence

Our board has determined each of Robert Grabb, Jack King, Lisa Meier, Loren J. O’Toole and Carter Stewart to be an “independent director” as defined in Section 803.A(2) of the NYSE Amex Company Guide. In this regard, the board of directors has affirmatively determined that a majority of its members are independent directors. There are no familial relationships between any of our directors and executive officers.

PART IV

Item 15. Exhibits and Financial Statement Schedules


(a)	Documents filed as Part of this Report:

	1.	Financial Statements
		See Index to Financial Statements on page F-1.

	2.	Financial Statement Schedules
		Supplemental Oil and Gas Information Quarterly Results of Operations

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

(b)	Exhibits:

Unless otherwise indicated, all documents incorporated by reference into this report are filed with the SEC pursuant to the Securities and Exchange Act of 1934, as amended, under file number 001-33999.


Exhibit No.	Description	Reference
3.1	Composite Articles of Incorporation of Northern Oil and Gas, Inc.	Incorporated by reference to Exhibit 3.1 to our company’s Annual Report on Form 10-K/A (Amendment No. 3) filed with the SEC on June 24, 2009
3.2	Amended and Restated Bylaws of Northern Oil and Gas, Inc.	Incorporated by reference to Exhibit 99.2 to the Registrant’s Current Report on Form 8-K filed with the SEC on December 6, 2007 (File No. 000-30955)
4.1	Specimen Stock Certificate of Northern Oil and Gas, Inc.	Incorporated by reference to Exhibit 2.2 to the Registration Statement on Form SB-2 filed with the SEC on June 11, 2007, as amended (File No. 333-143648)
10.1	Form of Warrant	Incorporated by reference to Exhibit 10.2 to the current report on Form 8-K filed with the SEC on September 14, 2007 (File No. 000-30955)
10.2*	Amended and Restated Employment Agreement by and between Northern Oil and Gas, Inc. and Michael L. Reger, dated January 30, 2009	Incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 2, 2009 (File No. 000-30955)
10.3*	Amended and Restated Employment Agreement by and between Northern Oil and Gas, Inc. and Ryan R. Gilbertson, dated January 30, 2009	Incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 2, 2009 (File No. 000-30955)
10.4	Irrevocable Proxy Provided by Joseph A. Geraci II, Kimerlie Geraci, Lantern Advisers, LLC, Isles Capital, LLC and Mill City Ventures, LP, dated February 21, 2008	Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on March 19, 2008 (File No. 000-30955)
10.5	Agreement by and between Northern Oil and Gas, Inc. and Deephaven MCF Acquisition LLC dated April 14, 2008	Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on April 16, 2008 (File No. 000-30955)
10.6	Second Amendment to Agreement by and between Northern Oil and Gas, Inc. and Deephaven MCF Acquisition LLC dated April 14, 2008	Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on September 29, 2008 (File No. 000-30955)


Exhibit No.	Description	Reference
10.7	Registration Rights Agreement By and Among Northern Oil and Gas, Inc. and Deephaven MCF Acquisition LLC dated April 14, 2008	Incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed with the SEC on April 16, 2008 (File No. 000-30955)
10.8	Lease Purchase Agreement By and Between Northern Oil and Gas, Inc. and Woodstone Resources, L.L.C.	Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on June 17, 2008 (File No. 000-30955)
10.9	Northern Oil and Gas, Inc. 2009 Equity Compensation Plan	Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 2, 2009 (File No. 000-30955)
10.10	Credit Agreement dated as of February 27, 2009 among Northern Oil and Gas, Inc., as Borrower, CIT Capital USA Inc., as Administrative Agent, and The Lenders Party Hereto	Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on March 2, 2009 (File No. 000-30955)
10.11	Form of Note Under that Certain Credit Agreement dated as of February 27, 2009 among Northern Oil and Gas, Inc., as Borrower, CIT Capital USA Inc., as Administrative Agent, and The Lenders Party Hereto	Incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed with the SEC on March 2, 2009 (File No. 000-30955)
10.12	Guaranty and Collateral Agreement dated as of February 27, 2009 made by Northern Oil and Gas, Inc. in favor of CIT Capital USA Inc., as Administrative Agent	Incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed with the SEC on March 2, 2009 (File No. 000-30955)
10.13	Guaranty and Collateral Agreement dated as of February 27, 2009 made by Northern Oil and Gas, Inc. in favor of CIT Capital USA Inc., as Administrative Agent	Incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed with the SEC on March 2, 2009 (File No. 000-30955)
10.14	Warrant to Purchase Shares of Northern Oil and Gas, Inc. Common Stock Issued to CIT Group/Equity Investments, Inc. on February 27, 2009	Incorporated by reference to Exhibit 10.5 to the Registrant’s Current Report on Form 8-K filed with the SEC on March 2, 2009 (File No. 000-30955)
10.15*	Northern Oil and Gas, Inc. 2009 Equity Incentive Plan	Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Registration Statement on Form S-8 filed with the SEC on July 16, 2009 (File No. 333-160602)
10.16	Exploration and Development Agreement dated effective as of April 1, 2009 by and between Slawson Exploration Company, Inc. and Northern Oil and Gas, Inc.	Incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on May 29, 2009
10.17	First Amendment to Credit Agreement dated as of May 22, 2009 among Northern Oil and Gas, Inc., CIT Capital USA Inc., and the Lenders party thereto	Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on May 29, 2009
10.18*	Form of Promissory Note issued to Michael L. Reger and Ryan R. Gilbertson	Incorporated by reference to Exhibit 10.18 to the Registrant’s Annual Report on Form 10-K filed with the filed with the SEC on March 3, 2010.
10.19*	Form of Restricted Stock Agreement issued under the Northern Oil and Gas, Inc. 2009 Equity Incentive Plan	Incorporated by reference to Exhibit 10.19 to the Registrant’s Annual Report on Form 10-K filed with the filed with the SEC on March 3, 2010.
18.1	Letter from Mantyla McReynolds, LLC Regarding Change in Accounting Principles	Incorporated by reference to Exhibit 18.1 to the Registrant’s Current Report on Form 10-Q filed with the SEC on October 27, 2009
23.1	Consent of Independent Registered Public Accounting Firm Mantyla McReynolds LLC	Filed herewith
23.2	Consent of Ryder Scott Company, LP	Filed herewith
24.1	Powers of Attorney	Included on Signature Page to Original Filing


Exhibit No.	Description	Reference
31.1	Certification of the Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith
31.2	Certification of the Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith
32.1	Certification of the Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith
99.1	Report of Ryder Scott Company, LP.	Incorporated by reference to Exhibit 99.1 to the Registrant’s Annual Report on Form 10-K filed with the filed with the SEC on March 4, 2010.

* Management contract or compensatory plan or arrangement required to be filed as an exhibit to this report.

SIGNATURES

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

		NORTHERN OIL AND GAS, INC.

Date:	September 16, 2011	By:	/s/ Michael L. Reger
			Michael L. Reger
			Chief Executive Officer

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

Signature	Title	Date

	Chief Executive Officer and Director	September 16, 2011
Michael L. Reger	Chief Executive Officer and Director

	Chief Financial Officer, Principal Financial Officer and Principal Accounting Officer	September 16, 2011
Chad D. Winter

/s/ Richard D. Weber	Director	September 16, 2011
Richard D. Weber	Director

*	Director	September 16, 2011
Loren J. O’Toole

/s/ Delos Cy Jamison	Director	September 16, 2011
Delos Cy Jamison

*	Director	September 16, 2011
Jack King

*	Director	September 16, 2011
Robert Grabb

*	Director	September 16, 2011
Lisa Bromiley Meier

* Michael L. Reger, by signing his name hereto, does hereby sign this document on behalf of the above-named directors of the Registrant pursuant to powers of attorney duly executed by such persons.

	By:	/s/ Michael L. Reger
		Michael L. Reger
		Attorney-in-Fact

NORTHERN OIL AND GAS, INC.

INDEX TO FINANCIAL STATEMENTS


		Page
Report of Independent Registered Public Accounting Firm		F-2
Balance Sheets as of December 31, 2010 and 2009		F-3
Statements of Operations for the Years Ended December 31, 2010, December 31, 2009 and December 31, 2008		F-4
Statements of Cash Flows for the Years Ended December 31, 2010, December 31, 2009 and December 31, 2008		F-5
Statements of Stockholder’s Equity for the Years Ended December 31, 2010, December 31, 2009 and December 31, 2008		F-7
Notes to the Financial Statements		F-10

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders
Northern Oil and Gas, Inc.:

We have audited the accompanying balance sheets of Northern Oil and Gas, Inc. (the Company) as of December 31, 2010 and 2009, and the related statements of operations, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 4, 2011 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

Mantyla McReynolds LLC
Salt Lake City, Utah
March 4, 2011

F-2

NORTHERN OIL AND GAS, INC.
BALANCE SHEETS
DECEMBER 31, 2010 AND 2009


	December 31,
	2010			2009
CURRENT ASSETS
Cash and Cash Equivalents	$	152,110,701		$	6,233,372
Trade Receivables		22,033,647			7,025,011
Prepaid Drilling Costs		13,225,650			1,454,034
Prepaid Expenses		345,695			143,606
Other Current Assets		475,967			201,314
Short - Term Investments		39,726,700			24,903,476
Deferred Tax Asset		5,100,000			2,057,000
Total Current Assets		233,018,360			42,017,813

PROPERTY AND EQUIPMENT
Oil and Natural Gas Properties, Full Cost Method of Accounting
Proved		158,846,475			42,939,097
Unproved		136,135,163			53,862,529
Other Property and Equipment		2,479,199			439,656
Total Property and Equipment		297,460,837			97,241,282
Less - Accumulated Depreciation and Depletion		22,152,356			5,091,198
Total Property and Equipment, Net		275,308,481			92,150,084

DEBT ISSUANCE COSTS		1,367,124			1,427,071
Total Assets	$	509,693,965		$	135,594,968

LIABILITIES AND STOCKHOLDER’S EQUITY
CURRENT LIABILITIES
Accounts Payable	$	48,500,204		$	6,419,534
Line of Credit		-			834,492
Accrued Expenses		2,829			316,977
Derivative Liability		11,145,319			1,320,679
Other Liabilities		18,574			18,574
Total Current Liabilities		59,666,926			8,910,256

LONG-TERM LIABILITIES
Revolving Line of Credit		-			-
Derivative Liability		5,022,657			1,459,374
Subordinated Notes		-			500,000
Other Noncurrent Liabilities		477,900			243,888
Total Long-Term Liabilities		5,500,557			2,203,262

DEFERRED TAX LIABILITY		9,167,000			922,000
Total Liabilities		74,334,483			12,035,518

STOCKHOLDERS’ EQUITY
Preferred Stock, Par Value $.001; 5,000,000 Authorized, No Shares Outstanding		-			-
Common Stock, Par Value $.001; 95,000,000 Authorized, 62,129,424 Outstanding (2009 – 43,911,044 Shares Outstanding)		62,129			43,912
Additional Paid-In Capital		428,484,092			124,884,266
Retained Earnings		7,759,192			841,892
Accumulated Other Comprehensive Income (Loss)		(945,931	)		(2,210,620	)
Total Stockholders’ Equity		435,359,482			123,559,450
Total Liabilities and Stockholders’ Equity	$	509,693,965		$	135,594,968

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

F-3

NORTHERN OIL AND GAS, INC.
STATEMENT OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009, AND 2008


	Year Ended December 31,
	2010			2009			2008 Adjusted *
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			-
		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
Depletion of Oil and Gas Properties		16,884,563			4,250,983			677,915
Depreciation and Amortization		176,595			91,794			67,060
Accretion of Discount on Asset Retirement Obligations		21,755			8,082			1,030
Total Expenses		33,053,812			10,092,538			3,111,430

INCOME FROM OPERATIONS		11,505,288			4,128,961			1,210,449

OTHER INCOME (EXPENSE)		(168,988	)		135,991			383,891

INCOME BEFORE INCOME TAXES		11,336,300			4,264,952			1,594,340

INCOME TAX PROVISION (BENEFIT)		4,419,000			1,466,000			(830,000	)

NET INCOME	$	6,917,300		$	2,798,952		$	2,424,340

Net Income Per Common Share - Basic	$	0.14		$	0.08		$	0.08

Net Income Per Common Share - Diluted	$	0.14		$	0.08		$	0.07

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

*See Note 2

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

F-4

NORTHERN OIL AND GAS, INC.
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009, AND 2008


	Year Ended December 31,
	2010			2009			2008 Adjusted *
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	6,917,300		$	2,798,952		$	2,424,340
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Depletion of Oil and Gas Properties		16,884,563			4,250,983			677,915
Depreciation and Amortization		176,595			91,794			67,060
Amortization of Debt Issuance Costs		455,302			459,343			-
Accretion of Discount on Asset Retirement Obligations		21,755			8,082			1,030
Income Tax Provision (Benefit)		4,419,000			1,466,000			(830,000	)
Issuance of Stock for Consulting Fees		-			-			49,875
Net Loss on Sale of Available for Sale Securities		58,524			-			381
Market Value adjustment of Derivative Instruments		14,545,477			363,414			(95,148	)
Lease Incentives Received		-			-			91,320
Amortization of Deferred Rent		(18,573	)		(18,573	)		(17,026	)
Share - Based Compensation Expense		3,566,133			1,213,292			105,375
Changes in Working Capital and Other Items:
Increase in Trade Receivables		(15,008,636	)		(4,996,070	)		(2,028,941	)
Increase (Decrease) in Other Receivables		-			874,453			(874,453	)
Increase in Prepaid Expenses		(202,089	)		(72,052	)		(45,874	)
Increase in Other Current Assets		(274,653	)		(158,334	)		-
Increase in Accounts Payable		42,080,670			4,484,724			1,821,556
Increase (Decrease) in Accrued Expenses		(314,148	)		(953,098	)		1,159,082
Net Cash Provided By Operating Activities		73,307,220			9,812,910			2,506,492

CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of Other Equipment and Furniture		(2,039,543	)		(31,256	)		(363,631	)
Decrease (Increase) in Prepaid Drilling Costs		(11,771,616	)		(1,449,485	)		359,741
Proceeds from Sale of Oil and Gas Properties		297,877			-			468,609
Purchase of Available for Sale Securities		(48,679,264	)		(24,106,294	)		(3,800,524	)
Proceeds from Sale of Available for Sale Securities		34,699,651			800,000			975,000
Purchase of Oil and Gas Properties		(180,400,555	)		(47,061,666	)		(37,997,157	)
Net Cash Used For Investing Activities		(207,893,450	)		(71,848,701	)		(40,357,962	)

CASH FLOWS FROM FINANCING ACTIVITIES
Increase in Margin Loan		-			-			1,650,720
Payments on Line of Credit		(834,492	)		(816,228	)		-
Advances on Revolving Credit Facility		5,300,000			29,750,000			-
Repayments on Revolving Credit Facility		(5,300,000	)		(29,750,000	)		-
Cash Paid for Listing Fee		-			-			(65,000	)
Proceeds from Derivatives		-			-			95,148
Increase (Decrease) in Subordinated Notes, net		(500,000	)		500,000
Debt Issuance Costs Paid		(395,355	)		(1,190,061	)		-
Proceeds from the Issuance of Common Stock - Net of Issuance Costs		282,193,406			68,994,736			25,904,858
Proceeds from Exercise of Stock Options		-			-			933,800
Net Cash Provided by Financing Activities		280,463,559			67,488,447			28,519,526

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		145,877,329			5,452,656			(9,331,944	)

CASH AND CASH EQUIVALENTS – BEGINNING OF PERIOD		6,233,372			780,716			10,112,660

CASH AND CASH EQUIVALENTS – END OF PERIOD	$	152,110,701		$	6,233,372		$	780,716

F-5


	Year Ended December 31,
	2010		2009		2008 Adjusted *

Supplemental Disclosure of Cash Flow Information
Cash Paid During the Period for Interest	$	169,232	$	624,717	$	-
Cash Paid During the Period for Income Taxes	$	-	$	-	$	-

Non-Cash Financing and Investing Activities:
Purchase of Oil and Gas Properties through Issuance of Common Stock	$	12,679,422	$	1,115,738	$	2,084,372
Payment of Consulting Fees through Issuance of Common Stock	$	-	$	-	$	49,875
Payment of Compensation through Issuance of Common Stock	$	8,733,215	$	1,213,292	$	105,375
Capitalized Asset Retirement Obligations	$	232,258	$	137,222	$	60,407.00
Cashless Exercise of Stock Options	$	-	$	518,000	$	-
Fair Value of Warrants Issued for Debt Issuance Costs	$	-	$	221,153	$	-
Payment of Debt Issuance Costs through Issuance of Common Stock	$	-	$	475,200	$	-

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

* See Note 2

F-6

NORTHERN OIL AND GAS, INC.
STATEMENT OF STOCKHOLDERS’ EQUITY (DEFICIT)
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009, AND 2008


	Common Stock				Additional Paid-In Capital			Accumulated Other Comprehensive Income (Loss)			Retained Earnings (Accumulated Deficit)			Total Stockholders’ Equity



	Shares		Amount
Balance – December 31, 2007		28,695,922	$	28,696	$	22,259,921		$	-		$	4,381,400	)	$	17,907,217

Issued 7,500 Common Shares to Roepke Communications for services		7,500		8		49,867			-			-			49,875

Issued 318,495 Common Shares for Leasehold Interest Gas Properties, LLC for Leasehold Interest (Value between $2.30 and $11.98 per Common Share)		318,495		319		2,084,053			-			-			2,084,372

Issued 20,000 Common Shares of Restricted Stock for employee services		20,000		20		(20	)		-			-			-

Listing Fee Paid to American Stock Exchange		-		-		(65,000	)		-			-			(65,000	)

Issued Pursuant to Exercise of Options		260,000		260		933,540			-			-			933,800

Issued Pursuant to Exercise of Warrants		4,818,186		4,818		25,977,244			-			-			25,982,062

Warrant Exercise Costs		-		-		(77,204	)		-			-			(77,204	)

Stock Grant Compensation		-		-		105,375			-			-			105,375

Unrealized Losses on Auction Rate Securities		-		-		-			(240,774	)		-			(240,774	)

Income Tax Benefit from Options Exercised		-		-		425,000			-			-			425,000

Net Income - As Adjusted		-		-		-						2,424,340			2,424,340

Balance – December 31, 2008		34,120,103	$	34,121	$	51,692,776		$	(240,774	)	$	(1,957,060	)	$	49,529,063

Warrants Issued Included for Debt Issuance Costs		-		-		221,153			-			-			221,153

Stock Grant Compensation		-		-		366,690			-			-			366,690

Net Change in Cash Flow Hedge Derivatives		-		-		-			(1,483,639	)		-			(1,483,639	)

F-7


	Common Stock						Additional Paid-In Capital			Accumulated Other Comprehensive Income (Loss)			Retained Earnings (Accumulated Deficit)		Total Stockholders’ Equity



	Shares			Amount
Unrealized Gain on Short-Term Investments		-			-			-			(486,207	)		-		(486,207	)
Issued 180,000 shares as Debt Issuance Costs		180,000			180			475,020			-			-		475,200

Issued 283,670 Shares as Compensation/Director Fees (Value between $2.84 and $9.70 per Common Share)		283,670			284			2,092,695			-			-		2,092,979

Sale of 2,250,000 Common Shares for $6.00 Per Share		2,250,000			2,250			13,497,750			-			-		13,500,000

Sale of 6,500,000 Common Shares for $9.12 Per Share		6,500,000			6,500			59,273,500			-			-		59,280,000

Issued 128,907 Common Shares for Leasehold Interest (Value between $4.25 and $11.46 per Common Share)		128,097			128			1,115,610			-			-		1,115,738

Repurchase of 2,084 Common Shares		(2,084	)		(2	)		(20,213	)		-			-		(20,215	)

Costs of Capital Raise		-			-			(3,785,264	)		-			-		(3,785,264	)

Issued 361,330 Common Shares of Restricted Stock		361,330			361			(361	)		-			-		-

Repurchase of 52,061 Common Shares		(52,061	)		(52	)		(517,948	)		-			-		(518,000	)

Issued Pursuant to Exercise of Options		100,000			100			517,900			-			-		518,000

Share Adjustment Related to Kentex Transaction		41,989			42			(42	)		-			-		-

Income Tax Provision for Share Based Compensation		-			-			(45,000	)		-			-		(45,000	)

Net Income		-			-			-			-			2,798,952		2,798,952

Balance - December 31, 2009		43,911,044		$	43,912		$	124,884,266		$	(2,210,620	)	$	841,892	$	123,559,450

Stock Grant Compensation		-			-			4,439,101			-			-		4,439,101

Net Change in Cash Flow Hedge Derivatives		-			-			-			711,554			-		711,554

Net Change in Unrealized Gain(Loss) on Short-term Investments		-			-			-			553,135			-		553,135

Issued 213,075 Shares as Compensation (Value between $12.32 and $22.85 per Common Share)		213,075			211			4,293,903			-			-		4,294,114

F-8


	Common Stock				Additional Paid-In Capital			Accumulated Other Comprehensive Income (Loss)			Retained Earnings (Accumulated Deficit)		Total Stockholders’ Equity



	Shares		Amount

Sale of 5,750,000 Common Shares for $14.40 Per Share		5,750,000		5,750		82,794,250			-			-		82,800,000

Sale of 10,292,500 Common Shares for $20.25 Per Share (Net of Underwriting Fee of $8,336,925)		10,292,500		10,293		200,075,907			-			-		200,086,200

Issued 882,491 Common Shares for Leasehold Interest (Value between $9.67 and $16.80 per Common Share)		882,491		883		12,678,539			-			-		12,679,422

Cost of Capital Raises		-		-		(692,794	)		-			-		(692,794	)

Issued 1,058,000 Common Shares of Restricted Stock		1,058,000		1,058		(1,058	)		-			-		-

Issued Pursuant to Cashless Exercise of Stock Options		22,314		22		(22	)		-			-		-

Income Tax Provision for Share Based Compensation		-		-		12,000			-			-		12,000

Net Income		-		-		-			-			6,917,300		6,917,300

Balance - December 31, 2010	$	62,129,424	$	62,129	$	428,484,092		$	(945,931	)	$	7,759,192	$	435,359,482

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

F-9

NOTES TO FINANCIAL STATEMENTS

DECEMBER 31, 2010

NOTE 1 ORGANIZATION AND NATURE OF BUSINESS

Northern Oil and Gas, Inc. (the “Company,” “our” and words of similar import) is a growth-oriented independent energy company engaged in the acquisition, exploration, exploitation and development of crude oil and natural gas properties. The Company’s common stock trades on the NYSE Amex Equities Market under the symbol “NOG”.

The Company acquires interests in crude oil and natural gas acreage and drilling projects, primarily within the Williston Basin Bakken Shale formation. The Company is continuing to develop its substantial leasehold acreage in the Bakken play and will target additional opportunities in the Bakken and Three Forks play utilizing its first mover leasing advantage. The Company owns working interest in wells, and does not lease land to operators. Management believes the Company’s advantage gained by participating as a non-operating partner has given the Company valuable data on completions and will help its operating partners control well costs and enhance results as the Company continues to develop its higher working interest sections in 2011 and beyond.

The Company participates on a heads up basis proportionate to its working interest in declared drilling units. As of December 31, 2010, our principal assets included approximately 153,170 net acres located in the northern region of the United States of which the Company controlled approximately 140,216 net mineral acres in the Williston Basin targeting the Bakken and Three Forks formations. The Company continues to expand its position through aggressive acquisition and leasing programs.

The Company’s land acquisition and field operations, along with various other services, are primarily outsourced through the use of consultants and drilling partners. The Company will continue to retain independent contractors to assist in operating and managing the prospects and other administrative functions. With the additional acquisition of crude oil and natural gas properties, the Company intends to continue to use both in-house employees and outside consultants to develop and exploit its leasehold interests.

As an independent crude oil and natural gas producer, the Company’s revenue, profitability and future rate of growth are substantially dependent on prevailing prices of crude oil and natural gas. A substantial or extended decline in crude oil or natural gas prices could have a material adverse effect on the Company’s financial position, results of operations, cash flows and access to capital, and on the quantities of natural gas and crude oil reserves that can be economically produced.

NOTE 2 SIGNIFICANT ACCOUNTING POLICIES

These financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”).

Cash and Cash Equivalents

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

Short-Term Investments

All marketable debt and equity securities and United States Treasuries that are included in short-term investments are considered available-for-sale and are carried at fair value. The short-term investments are considered current assets due their maturity term or the Company’s ability and intent to use them to fund current operations. The unrealized gains and losses related to these securities are included in accumulated other comprehensive income (loss). The realized gains and losses related to these securities are included in other income (expense) in the statements of operations.

F-10

Other Property and Equipment

Property and equipment that are not crude oil and natural gas properties are recorded at cost and depreciated using the straight-line method over their estimated useful lives of three to fifteen years. Expenditures for replacements, renewals, and betterments are capitalized. Maintenance and repairs are charged to operations as incurred. Long-lived assets, other than crude oil and natural gas properties, are evaluated for impairment to determine if current circumstances and market conditions indicate the carrying amount may not be recoverable. The Company has not recognized any impairment losses on non crude oil and natural gas long-lived assets. Depreciation expense was $176,595, $91,794, and $67,060 for the years ended December 31, 2010, 2009, and 2008.

Debt Issuance Costs

In February 2009, the Company entered into a revolving credit facility with CIT Capital USA, Inc. (“CIT”) (See Note 9). The Company incurred costs related to this facility that were capitalized on the Balance Sheet as Debt Issuance Costs. Included in the Debt Issuance Costs are direct costs paid to third parties for broker fees and legal fees, 180,000 shares of restricted common stock paid as additional compensation for broker fees, and the fair value of 300,000 warrants issued to CIT. The fair value of the warrants was calculated using the Black-Scholes valuation model based on factors present at the time of closing. CIT exercised these warrants at a price of $5.00 per share in January 2011. The initial total amount capitalized for Debt Issuance Costs was $1,670,000 related to the original agreement with CIT. In May 2009, the Company amended the revolving credit facility with CIT to allow for additional borrowings. The Company incurred and capitalized $216,414 of direct costs related to this amendment.

In May 2010, the Company completed an assignment of its revolving credit facility to Macquarie Bank Limited (“Macquarie”) from CIT. In connection with the assignment, the Company and Macquarie entered into an Amended and Restated Credit Agreement governing the credit facility. The Company incurred and capitalized $386,179 of direct costs related to this assignment and amendment.

The remaining capitalized costs from the original February 2009 agreement and the May 2009 amendment to the agreement and the additional costs for the assignment and amendment of the facility in May 2010 are being amortized over the remaining term of the amended facility using the effective interest method.

The amortization of debt issuance costs for the year ended December 31, 2010 and 2009 was $455,302 and $459,343, respectively.

Asset Retirement Obligations

The Company records the fair value of a liability for an asset retirement obligation in the period in which the asset is acquired and a corresponding increase in the carrying amount of the related long-lived asset. The Asset Retirement Obligation is included in Other Noncurrent Liabilities on the balance sheet. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.

Revenue Recognition and Natural Gas Balancing

The Company recognizes crude oil and natural gas revenues from its interests in producing wells when production is delivered to, and title has transferred to, the purchaser and to the extent the selling price is reasonably determinable. The Company uses the sales method of accounting for natural gas balancing of natural gas production and would recognize a liability if the existing proven reserves were not adequate to cover the current imbalance situation. As of December 31, 2010, 2009, and 2008, the Company’s natural gas production was in balance, meaning its cumulative portion of natural gas production taken and sold from wells in which it has an interest equaled its entitled interest in natural gas production from those wells.

F-11

Stock-Based Compensation

The Company has accounted for stock-based compensation under the provisions of FASB Accounting Standards Codification (ASC) 718-10-55. This standard requires the Company to record an expense associated with the fair value of stock-based compensation. For options, the Company uses the Black-Scholes option valuation model to calculate stock based compensation at the date of grant. Option pricing models require the input of highly subjective assumptions, including the expected price volatility. Changes in these assumptions can materially affect the fair value estimate.

Income Taxes

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

Stock Issuance

The Company records the stock-based compensation awards issued to non-employees and other external entities for goods and services at either the fair market value of the goods received or services rendered or the instruments issued in exchange for such services, whichever is more readily determinable, using the measurement date guidelines enumerated in FASB ASC 505-50-30.

Net Income (Loss) Per Common Share

Basic earnings per share (“EPS”) are computed by dividing net income (the numerator) by the weighted average number of common shares outstanding for the period (the denominator). Diluted EPS is computed by dividing net income by the weighted average number of common shares and potential common shares outstanding (if dilutive) during each period. Potential common shares include stock options and warrants. The number of potential common shares outstanding relating to stock options and warrants is computed using the treasury stock method.

As of December 31, 2010, there were 265,963 potentially dilutive shares from stock options that became exercisable in 2007.

In addition, as of December 31, 2010, there were 300,000 warrants that were issued in conjunction with the February 2009 revolving credit facility with CIT that remained outstanding and exercisable. The warrants were exercised at a price of $5.00 per share in January 2011.

Full Cost Method

The Company follows the full cost method of accounting for crude oil and natural gas operations whereby all costs related to the exploration and development of crude oil and natural gas properties are initially capitalized into a single cost center (“full cost pool”). Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisition, and exploration activities. Internal costs that are capitalized are directly attributable to acquisition, exploration and development activities and do not include costs related to the production, general corporate overhead or similar activities. Costs associated with production and general corporate activities are expensed in the period incurred. Capitalized costs are summarized as follows for the years ended December 31, 2010, 2009, and 2008:

F-12


	Year Ended December 31,
	2010		2009		2008
Capitalized Certain Payroll and Other Internal Costs	$	6,559,741	$	2,616,262	$	1,374,071
Capitalized Interest Costs		59,711		624,717		-
Total	$	6,619,452	$	3,240,979	$	1,374,071

As of December 31, 2010, the Company controlled acreage in Sheridan County, Montana with primary targets including the Red River and Mission Canyon. The Company controlled acreage in Billings, Burke, Divide, Dunn, Golden Valley, McKenzie, Mountrail, Stark and Williams Counties, North Dakota targeting the Bakken and Three Forks formations as well as acreage in Yates County, New York that is prospective for Trenton/Black River, Marcellus and Queenstown-Medina natural gas production. See Note 5 for explanation of activities on these properties.

Proceeds from property sales will generally be credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 25% or more of the proved reserves related to a single full cost pool. In the years ended December 31, 2010 and 2008, the Company sold acreage and production for $297,877 and $468,609. The proceeds for these sales were applied to reduce the capitalized costs of crude oil and natural gas properties. There were no property sales for the year ended December 31, 2009.

Capitalized costs associated with impaired properties and capitalized cost related to properties having proved reserves, plus the estimated future development costs, asset retirement costs under FASB ASC 410-20-25 are depleted and amortized on the unit-of-production method based on the estimated gross proved reserves as determined by independent petroleum engineers. The costs of unproved properties are withheld from the depletion base until such time as they are either developed or abandoned. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion calculations. As of December 31, 2010, the Company included $1,591,790 of costs related to expired leases in Sheridan County, Montana and Yates County, New York, which costs are subject to the depletion calculation.

Capitalized costs of crude oil and natural gas properties (net of related deferred income taxes) may not exceed an amount equal to the present value, discounted at 10% per annum, of the estimated future net cash flows from proved crude oil and natural gas reserves plus the cost of unproved properties (adjusted for related income tax effects). Should capitalized costs exceed this ceiling, impairment is recognized. The present value of estimated future net cash flows is computed by applying the 12-month average price of crude oil and natural gas to estimated future production of proved crude oil and natural gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves and assuming continuation of existing economic conditions. Such present value of proved reserves’ future net cash flows excludes future cash outflows associated with settling asset retirement obligations that have been accrued on the Balance Sheet. Should this comparison indicate an excess carrying value, the excess is charged to earnings as an impairment expense. As of December 31, 2010, the Company has not realized any impairment of its properties due to our low basis in the acreage and productivity and economics of its producing wells.

Use of Estimates

The preparation of financial statements under generally accepted accounting principles (“GAAP”) in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates relate to proved crude oil and natural gas reserve volumes, future development costs, estimates relating to certain crude oil and natural gas revenues and expenses, fair value of derivative instruments, fair value of certain investments, and deferred income taxes. Actual results may differ from those estimates.

F-13

Reclassifications

Certain reclassifications have been made to prior years’ reported amounts in order to conform with the current year presentation. In prior years the Company separately indentified share based compensation on its statement of operations. These amounts have been reclassified to be included in general and administrative expense. These reclassifications did not impact the Company’s net income, stockholders’ equity or cash flows.

Derivative Instruments and Price Risk Management

The Company uses derivative instruments from time to time to manage market risks resulting from fluctuations in the prices of crude oil and natural gas. The Company may periodically enter into derivative contracts, including price swaps, caps and floors, which require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of crude oil or natural gas without the exchange of underlying volumes. The notional amounts of these financial instruments are based on expected production from existing wells. The Company has, and may continue to use exchange traded futures contracts and option contracts to hedge the delivery price of crude oil at a future date.

At the inception of a derivative contract, the Company historically designated the derivative as a cash flow hedge. For all derivatives designated as cash flow hedges, the Company formally documented the relationship between the derivative contract and the hedged items, as well as the risk management objective for entering into the derivative contract. To be designated as a cash flow hedge transaction, the relationship between the derivative and the hedged items must be highly effective in achieving the offset of changes in cash flows attributable to the risk both at the inception of the derivative and on an ongoing basis. The Company historically measured hedge effectiveness on a quarterly basis and hedge accounting would be discontinued prospectively if it determined that the derivative is no longer effective in offsetting changes in the cash flows of the hedged item. Gains and losses deferred in accumulated other comprehensive income related to cash flow hedge derivatives that become ineffective remain unchanged until the related production is delivered. If the Company determines that it is probable that a hedged forecasted transaction will not occur, deferred gains or losses on the derivative are recognized in earnings immediately. See Note 15 for a description of the derivative contracts which the Company executed during 2010 and 2009.

Derivatives, historically, were recorded on the balance sheet at fair value and changes in the fair value of derivatives were recorded each period in current earnings or other comprehensive income, depending on whether a derivative was designated as part of a hedge transaction and, if it was, depending on the type of hedge transaction. The Company’s derivatives historically consisted primarily of cash flow hedge transactions in which the Company was hedging the variability of cash flows related to a forecasted transaction. Period to period changes in the fair value of derivative instruments designated as cash flow hedges were reported in other comprehensive income and reclassified to earnings in the periods in which the contracts were settled. The ineffective portion of the cash flow hedges were reflected in current period earnings as gain or loss from derivative. Gains and losses on derivative instruments that did not qualify for hedge accounting were included in income or loss from derivatives in the period in which they occur. The resulting cash flows from derivatives were reported as cash flows from operating activities.

On November 1, 2009, due to the volatility of price differentials in the Williston Basin, the Company de-designated all derivatives that were previously classified as cash flow hedges and in addition, the Company has elected not to designate any subsequent derivative contracts as accounting hedges under FASB ASC 815-20-25. As such, all derivative positions are carried at their fair value on the balance sheet and are marked-to-market at the end of each period. Any realized gains and losses are recorded to Gain (Loss) on Settled Derivatives and unrealized gains or losses are recorded to Mark-to-Market of Derivative Instruments on the Statement of Operations rather than as a component of other comprehensive income (loss) or other Income (expense).

Impairment

FASB ASC 360-10-35-21, requires that long-lived assets to be held and used be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Oil and gas properties accounted for using the full cost method of accounting (which the Company uses) are excluded from this requirement but continue to be subject to the full cost method’s impairment rules. There was no impairment identified at December 31, 2010, 2009, and 2008.

F-14

Change in Accounting Principle Related to Drilling Costs

In 2009, the Company changed its 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 amounts are invoiced by operators is deemed preferable as it better represents the Company’s 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. Generally accepted accounting principles require that the impact of the change in accounting be applied retrospectively to all periods presented. As a result, all prior period financial statements have been adjusted to give effect to the cumulative impact of this change.

The following table shows the effects on the Company’s Balance Sheet:


	Year Ended December 31, 2008,
	As Reported			Adjusted			Effect of Change
Deferred Tax Asset – Current	$	1,433,000		$	1,390,000		$	(43,000	)
Oil and Gas Properties, Full Cost Method		55,680,567			47,260,838			(8,419,729	)
Accumulated Depreciation and Depletion		856,010			748,421			(107,589	)
Accrued Drilling Costs		8,419,729			-			(8,419,729	)
Accumulated Deficit	$	(2,021,649	)	$	(1,957,060	)	$	64,589

The following table shows the effect on the Company’s Statement of Operations:


	Year Ended December 31, 2008,
	As Reported			Adjusted			Effect of Change
Depletion Expense	$	785,504		$	677,915		$	(107,589	)
Income Tax Provision (Benefit)		(873,000	)		(830,000	)		43,000
Net Income	$	2,359,751		$	2,424,340		$	64,589
Earnings Per Share – Basic	$	0.07		$	0.08		$	0.01
Earnings Per Share – Diluted	$	0.07		$	0.07		$	-

The following table shows the effect on the Company’s Statement of Cash Flows:


	Year Ended December 31, 2008,
	As Reported			Adjusted			Effect of Change
Net Income	$	2,359,751		$	2,424,340		$	64,589
Depletion of Oil and Gas Properties		785,504			677,915			(107,589	)
Income Tax Benefit		(873,000	)		(830,000	)		43,000
Increase in Accrued Drilling Costs		8,419,729			-			(8,419,729	)
Increase in Oil and Gas Properties		(46,416,886	)		(37,997,157	)		8,419,729

New Accounting Pronouncements

In January 2010, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) No. 2010-06, Fair Value Measurements and Disclosures (Topic 820)–Improving Disclosures about Fair Value Measurements, which requires new disclosures and clarifies existing disclosure requirements related to fair value measurements. The new standard requires additional disclosures related to (i) the amounts of significant transfers between Level 1 and Level 2 fair value measurements and the reasons for the transfers, (ii) the reasons for any transfers in or out of Level 3 measurements, and (iii) the presentation of information in the rollforward of recurring Level 3 measurements about purchases, sales, issuances, and settlements on a gross basis. The new standard was effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosure requirements related to the gross presentation of purchases, sales, issuances, and settlements in the Level 3 rollforward. Those disclosures, which are not expected to have a material impact on the Company’s financial statements, are effective for fiscal years beginning after December 15, 2010 and will be incorporated into the Company’s Quarterly Report on Form 10-Q for the period ending March 31, 2011.

F-15

In February 2010, the FASB issued ASU 2010-09, “Subsequent Events (Topic 855) - Amendments to Certain Recognition and Disclosure Requirements.” ASU 2010-09 requires an entity that is a SEC filer to evaluate subsequent events through the date that the financial statements are issued and removes the requirement that a SEC filer disclose the date through which subsequent events have been evaluated. ASC 2010-09 was effective upon issuance. The adoption of this standard had no effect on the Company’s results of operations or financial position.

In April 2010, the FASB issued ASU 2010-13, “Compensation - Stock Compensation (Topic 718) - Effect of Denominating the Exercise Price of a Share-Based Payment Award in the Currency of the Market in Which the Underlying Equity Security Trades.” ASU 2010-13 provides amendments to Topic 718 to clarify that an employee share-based payment award with an exercise price denominated in the currency of a market in which a substantial portion of the entity’s equity securities trades should not be considered to contain a condition that is not a market, performance, or service condition. Therefore, an entity would not classify such an award as a liability if it otherwise qualifies as equity. The amendments in ASU 2010-13 are effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2010. The adoption of this standard will not have an effect on the Company’s results of operations or financial position.

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

NOTE 3 SHORT-TERM INVESTMENTS

All marketable debt and equity securities and United States Treasuries that are included in short-term investments are considered available-for-sale and are carried at fair value. The short-term investments are considered current assets due to their maturity term or the company’s ability and intent to use them to fund current operations. The unrealized gains and losses related to these securities are included in accumulated other comprehensive income (loss). The realized gains and losses related to these securities are included in other income in the statements of operations.

The following is a summary of our short-term investments as of December 31, 2010:


	Cost at December 31, 2010		Unrealized (Loss)			Fair Market Value at December 31, 2010
United States Treasuries	$	40,009,546	$	(282,846	)	$	39,726,700

For the year ended December 31, 2010, the Company realized losses of $58,524 on the sale of short-term investments. There were no realized gains and losses recognized on the sale of investments for the year ended December 31, 2009 and minimal gains or losses recognized on the sales of investments for the year ended December 31, 2008.

F-16

The Company reviews these investments on a quarterly basis to determine if it is probable that the Company will realize some portion of the unrealized loss in accordance with FASB ASC 320-10-35. In determining if the difference between cost and estimated fair value of the short-term investments was deemed either temporary or other-than-temporary impairment, the Company evaluated each type of short-term investment using a set of criteria including decline in value, duration of the decline, period until anticipated recovery, nature of investment, probability of recovery, financial condition and near-term prospects of the issuer, the Company’s intent and ability to retain the investment, attributes of the decline in value, status with rating agencies, status of principal and interest payments and any other issues related to the underlying securities. The Company determined the decline in the fair values in all of the short-term investments were temporary as of December 31, 2010.

NOTE 4 PROPERTY AND EQUIPMENT

Property and equipment at December 31, 2010 and 2009, consisted of the following:


	Year Ended December 31,
	2010		2009
Oil and Gas Properties, Full Cost Method
Unproved Costs, Not Subject to Amortization or Ceiling Test	$	136,135,163	$	53,862,529
Proved Costs		158,846,475		42,939,097
		294,981,638		96,801,626
Other Property and Equipment		2,479,199		439,656
		297,460,837		97,241,282
Less: Accumulated Depreciation, Depletion and Amortization
Property and Equipment		22,152,356		5,091,198
Total	$	275,308,481	$	92,150,084

The following table shows depreciation, depletion, and amortization expense by type of asset:


	Year Ended December 31,
	2010		2009
Depletion of Costs for Proved Oil and Gas Properties	$	16,884,563	$	4,250,983
Depreciation of Other Property and Equipment		176,595		91,794
Total Depreciation, Depletion, and Amortization Expense	$	17,061,158	$	4,342,777

NOTE 5 OIL AND GAS PROPERTIES

The value of the Company’s crude oil and natural gas properties consists of all acreage acquisition costs (including cash expenditures and the value of stock consideration), drilling costs and other associated capitalized costs. Each of these costs contributed to the Company’s approximate $198 million increase in crude oil and natural gas properties during 2010.

Acquisitions

Montana Acquisitions

At various points in 2009, the Company acquired leasehold interests in approximately 6,100 net mineral acres in development areas located in Roosevelt, Richland and Sheridan Counties, Montana, in which the Company is targeting the Bakken Shale.

On November 13, 2009, the Company entered into a Letter of Intent with Slawson pursuant to which the Company agreed to acquire a 20% working interest ownership in the exploration and development of Slawson’s Big Sky Project in Richland County, Montana for which Slawson controls leasehold interest in 13,401 gross acres and 11,586 net acres. For each well the Company elects to participate, the Company will pay a participation interest share of all costs to drill, equip, complete, test and plug such well(s) on an at cost basis.

F-17

North Dakota Acquisitions

At various points in late 2007 and throughout 2008, the Company acquired leasehold interests in approximately 21,498 net mineral acres of land via bulk purchases in the core development area of Mountrail County, North Dakota. The Company paid a combination of cash and stock as consideration for such acquisitions, including the issuance of an aggregate of 633,027 restricted shares of its common stock. In addition to these major acquisitions the Company completed a series of small transactions pursuant to which it purchased leasehold interests in approximately 8,000 net mineral acres in Mountrail County.

On June 11, 2008, the Company entered into a purchase agreement pursuant to which it ultimately acquired leasehold interests in approximately 23,210 net mineral acres primarily in Dunn County, North Dakota. The Company also completed various additional acquisitions of crude oil and natural gas leasehold interests through numerous small transactions with several parties in fiscal years 2007 and 2008.

At various points in 2007 and 2008, the Company purchased leasehold interests in approximately 10,000 net mineral acres in and around Burke and Divide Counties of North Dakota for cash consideration.

In May 2009, the Company entered into an exploration and development agreement with Slawson Exploration Company, Inc. (Slawson) pursuant to which the Company acquired certain North Dakota Bakken assets from Windsor Bakken LLC as part of a syndicate led by privately owned Slawson. Pursuant to the agreement, the Company purchased a 5% interest of the undeveloped acreage, including approximately 60,000 net acres. The Company also acquired an additional 9% interest in the existing well bores purchased from Windsor Bakken LLC, providing the Company an aggregate 14% interest in the existing 59 gross Bakken and Three Forks well bores in North Dakota including approximately 1,200 barrels of crude oil production per day. In the transaction, the Company purchased approximately 300,000 barrels of proven producing reserves as well as approximately 3,000 net undeveloped acres. The Company paid a total cost of $7,300,000 for the initial acquisition of acreage and well bore interests.

On November 3, 2009, along with Slawson the Company acquired 24 high working interest sections comprising approximately 12,000 net acres located in western McKenzie and Williams Counties of North Dakota. The Company acquired a 50% interest in these properties and will participate in drilling on a heads-up basis. These properties are proximal to several recent high-rate producing wells. The Company paid approximately $1,100 per net acre acquired in this acquisition and expect to begin drilling these properties in early 2011.

On November 17, 2009, the Company entered into an Exploration and Development Agreement with Area of Mutual Interest with Slawson pursuant to which the Company agreed to participate with a 50% working interest ownership, which equates to a 30% participation interest in the exploration and development of Slawson’s Anvil Project in Roosevelt and Sheridan Counties, Montana and Williams County, North Dakota. In the transaction, the Company acquired an interest in 12,500 net acres in leases at $750 per net acre for a 30% interest and an aggregate sum of $2,812,500. The Company agreed to participate in all costs to drill, equip, complete, test and plug the well and to pay costs for the well on an at cost basis. The Company has the option to elect to participate or not participate as to each well drilled in the applicable project area. For each well in which the Company elects to participate, the Company will pay a participation interest share of all costs to drill, equip, complete, test and plug such wells on an at cost basis.

During 2010, the Company acquired approximately 56,858 net mineral acres, for an average cost of $1,043 per net acre, in all of its key prospect areas in the form of both effective leases and top-leases.

During 2010, the Company completed acreage acquisitions involving properties spanning across the following counties of North Dakota: Burke, Divide, Dunn, McKenzie, Mountrail, Stark and Williams. The Company generally values acreage subject to near-term drilling activities on a lease-by-lease basis because it believes 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 the Company’s acreage acquisitions involve properties that are “hand-picked” by the Company 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, the Company generally views 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, the Company still reviews each lease on a lease-by-lease basis to ensure that the package as a whole meets its acquisition criteria and drilling expectations. In December of 2010, the Company acquired a 50% working interest from Slawson in approximately 14,538 net acres in Richland County, Montana. That acquisition accounted for approximately 12.8% of total number of net acres the Company acquired during 2010. No other acquisition involved more than 10% of the total acreage the Company acquired during the year.

F-18

In June of 2010, the Company acquired approximately 3,498 net acres for $1,750 per net acre in Williams and McKenzie Counties of North Dakota. The Company issued and aggregate of 382,645 shares of its common stock and paid $761,464 in cash as consideration for the acreage. The fair value of the stock issued was $5,360,859 or $14.01 per share, based upon the market value of the Company’s common stock in the date the shares were registered with the SEC for resale, which is the date the leasehold interests were acquired.

In July of 2010, the Company acquired approximately 3,352 net acres for $2,000 per net acre in Divide County, North Dakota. The Company issued 444,186 shares of common stock as consideration for the acreage. The fair value of the stock issued was $6,529,534 or $14.70 per share, based upon the market value of the Company’s common stock on the date the leasehold interest was acquired.

The Company has also completed other miscellaneous non-material acquisitions in North Dakota, and utilized a combination of stock and cash consideration for some of the acquisitions.

Certain of the foregoing acquisitions were purchased using the services of, or purchased from, parties considered to be related to the Company or the Company’s Chief Executive Officer, Michael L. Reger. See Note 7. All transactions involving related parties were approved by the Company’s Board of Directors or Audit Committee.

Unproved Properties

The Company’s unproved properties not being amortized comprise approximately 131,945 net acres of undeveloped leasehold interests. The Company believes that the majority of our unproved costs will become subject to depletion within the next five years by proving up reserves relating to the acreage through exploration and development activities, by impairing the acreage that will expire before the Company can explore or develop it further or by determining that further exploration and development activity will not occur.

Excluded costs for unproved properties are accumulated by year. Costs are reflected in the full cost pool as the drilling costs are incurred or as costs are evaluated and deemed impaired. The Company anticipates these excluded costs will be included in the depletion computation over the next five years. The Company is unable to predict the future impact on depletion rates. The following is a summary of capitalized costs excluded from depletion at December 31, 2010 by year incurred


	Year Ended December 31,
	2010		2009		2008		Prior Years
Property Acquisition	$	63,636,650	$	16,061,848	$	24,938,734	$	5,147,236
Drilling		26,350,695		-		-		-
Total	$	89,987,345	$	16,061,848	$	24,938,734	$	5,147,236

The Company 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.

The Company historically has acquired its 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. The Company generally participates 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.

F-19

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

The Company believes that the majority of its 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 the Company 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.


NOTE 6	PREFERRED AND COMMON STOCK

The Company’s Articles of Incorporation authorize the issuance of up to 100,000,000 shares. The shares are classified in two classes, consisting of 95,000,000 shares of common stock, par value $.001 per share, and 5,000,000 shares of preferred stock, par value $.001 per share. The Board of Directors is authorized to establish one or more series of preferred stock, setting forth the designation of each such series, and fixing the relative rights and preferences of each such series. The Company has neither designated nor issued any shares of preferred stock.

In 2008 optionees exercised 260,000 stock options granted in 2006 and 2007, resulting in cash proceeds to the Company of $933,800. A tax benefit of $425,000 related to fully vested stock option awards exercised was recorded as an increase to additional paid-in capital

In February 2009, the Company agreed to issue 92,000 shares of Common Stock to three employees of the company as compensation for their services. The employees were fully vested in the shares on the date of the grant. The fair value of the stock to be issued was $261,280 or $2.84 per share, the market value of a share of common stock on the date the stock was obligated to be issued. The entire amount of this stock award was expensed in the year ended December 31, 2009.

On February 27, 2009, the Company closed on a revolving credit facility with CIT Capital USA, Inc. (“CIT”). As part of obtaining this credit facility agreement the Company entered into an engagement with Cynergy Advisors, LLC (Cynergy). As part of the compensation for the work performed on obtaining the financing, Cynergy received 180,000 shares of restricted Common Stock of the Company. The fair value of the restricted stock was $475,200 or $2.64 per share, the market value of a share of Common Stock on the date the financing closed. The fair value of this stock was capitalized as Debt Issuance Costs and is being amortized over the amended term of the financing.

On April 3, 2009 the Company acquired leasehold interests in North Dakota. The total consideration paid for this acreage was 49,092 shares of restricted common stock. The fair value of the restricted stock was $224,879, or $4.58 per share, the market value of a share of Common Stock on the date the leasehold interests were acquired.

In June 2009, the Company completed a registered direct offering of 2,250,000 shares of common stock at a price of $6.00 per share for total gross proceeds of $13,500,000. The Company incurred costs of $813,237 related to this offering. These costs were netted against the proceeds of the offering through Additional Paid-In Capital.

On October 26, 2009, the Company deposited 41,989 shares of common stock in a specially-designated shareholder account that had been previously-created to hold shares of our common stock represented by certificates that appear in our stock transfer records but were known to have been cancelled and their underlying shares transferred between July of 1987 and August of 1999. An aggregate of 58,268 shares of our common stock are held in the specially-designated shareholder account, which, following a substantial review of all available historical stock transfer records, the Company concluded represents the maximum number of shares of our common stock that could potentially be released to shareholders who may be able to establish a valid claim to such shares due to previously unrecognized issues with the Company’s stock transfer records. These shares are considered issued and outstanding and are included in the total number of shares outstanding disclosed on the cover page of this report.

F-20

On November 4, 2009, the Company completed a registered direct offering of 6,500,000 shares of common stock at a price of $9.12 per share for total gross proceeds of $59,280,000. The Company incurred costs of $2,972,027 related to the offering. These costs were netted against the proceeds of the offering through Additional Paid-in Capital.

In November and December 2009, the issued 79,005 shares of common stock related to the purchase of leasehold interests in North Dakota. The fair value of the stock was $890,859, the market value of the Common Stock on the date the leasehold interests were acquired.

In November 2009, the Company issued 50,000 shares of Common Stock to two employees of the company as compensation for their services. The employees were fully vested in the shares on the date of the grant. The fair value of the stock issued was $457,500 or $9.15 per share, the market value of a share of common stock on the date the stock was issued. The entire amount of this stock award was expensed in the year ended December 31, 2009.

In December 2009, the Company issued 100,000 shares of Common Stock to two executives of the company as compensation for their services. The executives were fully vested in the shares on the date of the grant. The fair value of the stock issued was $970,000 or $9.70 per share, the market value of a share of common stock on the date the stock was issued. The entire amount of this stock award was expensed in the year ended December 31, 2009.

In December 2009, the Company issued 41,670 shares of Common Stock to the Company’s outside Directors as compensation for their services. The Directors were fully vested in the shares on the date of the grant. The fair value of the stock issued was $404,199 or $9.70 per share, the market value of a share of common stock on the date the stock was issued. The entire amount of this stock award was expensed in the year ended December 31, 2009.

In December 2009, a Director of the Company exercised 100,000 stock options granted to him in 2007. The exercise of these options was completed through a cashless exercise whereas the company repurchased 52,061 of common shares to issue the common shares related to this option exercise.

In January 2010, the Company agreed to issue an aggregate of 4,000 shares of Common Stock to two employees of the Company. The shares were fully vested on the date of the grant. The fair value of the stock issued was $50,280 or $12.57 per share, based upon the market value of one share of the Company’s common stock on the date the stock was obligated to be issued. The entire amount of this stock award was expensed in the year ended December 31, 2010.

In January 2010, the Company agreed to issue 1,000 shares of Common Stock to an independent contractor of the Company. The shares were fully vested on the date of the grant. The fair value of the stock issued was $12,320 or $12.32 per share, based upon the market value of one share of common stock on the date the stock was obligated to be issued. The entire amount of this stock award was expensed in the year ended December 31, 2010.

In March 2010, the Company issued 10,287 shares of Common Stock as part of an acquisition of leasehold interests in North Dakota. The fair value of the stock issued was $99,475 or $9.67 per share, based upon the market value of one share of common stock on the date the leasehold interests were acquired.

In March 2010, pursuant to employment agreements the Company issued an aggregate of 50,000 shares of Common Stock to executives of the Company. The shares were fully vested on the date of the grant. The fair value of the stock issued was $664,500 or $13.29 per share, based upon the market value of one share of common stock on the date the stock was obligated to be issued. The Company expensed $307,331 in share-based compensation related to the issuance for the year ended December 31, 2010. The remainder of the fair value was capitalized into the full cost pool.

In April 2010, the Company entered into an underwriting agreement to sell 5,750,000 shares of common stock at a price of $15.00 less an underwriting discount of $0.60 per share for total net proceeds of approximately $82.8 million, after deducting underwriters’ discounts. The Company incurred costs of $300,000 related to this offering. These costs were netted against the proceeds of the offering through Additional Paid-In Capital.

F-21

On June 14, 2010, the Company issued 382,645 shares of Common Stock as part of an acquisition of leasehold interests in North Dakota. The fair value of the stock issued was $5,360,856 or $14.01 per share, based upon the market value of one share of common stock on the date the shares were registered with the SEC for resale, which is the date the leasehold interests were acquired.

On June 18, 2010, the Company granted 14,167 shares of Common Stock related to acquisitions of leasehold interests in North Dakota. The fair value of the stock granted was $238,006 or $16.80 per share, based upon the market value of one share of common stock on the date the leasehold interests were acquired.

On July 13, 2010, the Company granted 31,206 shares of Common Stock related to acquisitions of leasehold interests in North Dakota. The fair value of the stock granted was $451,551 or $14.47 per share, based upon the market value of one share of common stock on the date the leasehold acquisitions were agreed upon.

On July 14, 2010, the Company granted 444,186 shares of Common Stock related to acquisitions of leasehold interests in North Dakota. The fair value of the stock granted was $6,529,534 or $14.70 per share, based upon the market value of one share of common stock on the date the leasehold interests were acquired.

In July 2010, pursuant to an employment agreement the Company issued 5,000 shares of Common Stock to an employee of the Company. The shares were fully vested on the date of the grant. The fair value of the stock issued was $69,250 or $13.85 per share, based upon the market value of one share of common stock on the date the stock was obligated to be issued. The entire amount of this stock award was expensed in the year ended December 31, 2010.

In November 2010, the Company entered into an underwriting agreement to sell 10,292,500 shares of common stock at a price of $20.25 less an underwriting discount of $0.81 per share for total net proceeds of approximately $200.1 million, after deducting underwriters’ discounts. The Company incurred costs of $392,795 related to this offering. These costs were netted against the proceeds of the offering through Additional Paid-In Capital.

In November 2010, the Company issued 153,075 fully vested shares of Common Stock to the executives and employees of the Company as compensation for their services. The fair value of the stock issued was $3,497,764 or $22.85 per share, the market value of a share of common stock on the date the stock was issued. The Company expensed $1,235,429 in share-based compensation related to the issuance for the year ended December 31, 2010. The remainder of the fair value was capitalized into the full cost pool.

Restricted Stock Awards

During the years ended December 31, 2010, 2009, and 2008,the Company issued 1,058,000, 361,330 and 20,000, respectively, restricted shares of common stock as compensation to officers, employees, and directors of the Company. The restricted shares vest over various terms with all restricted shares vesting no later than December 31, 2013. As of December 31, 2010, there was approximately $13.2 million of total unrecognized compensation expense related to unvested restricted stock. This compensation expense will be recognized over the remaining vesting period of the grants. The Company has assumed a zero percent forfeiture rate for restricted stock.

The following table reflects the outstanding restricted stock awards and activity related thereto for the years ended December 31:

F-22


	Year Ended December 31, 2010,					Year Ended December 31, 2009,					Year Ended December 31, 2008,
	Number of Shares			Weighted- Average Price		Number Of Shares			Weighted- Average Price		Number Of Shares		Weighted- Average Price
Restricted Stock Awards:
Restricted Shares Outstanding at the Beginning of the Year		325,330		$	9.01		20,000		$	7.03		-	$	-
Shares Granted		1,058,000		$	14.08		361,330		$	8.49		20,000	$	7.03
Lapse of Restrictions		(247,708	)	$	11.11		(56,000	)	$	4.91		-	$	-
Restricted Shares Outstanding at the End of the Year		1,135,622		$	13.28		325,330		$	9.01		20,000	$	7.03


NOTE 7	RELATED PARTY TRANSACTIONS

The Company has purchased leasehold interests from South Fork Exploration, LLC (“SFE”) pursuant to a continuous lease program that covers specific agreed upon sections of townships and ranges in Burke, Divide, and Mountrail Counties of North Dakota where SFE previously acquired leasehold interests on the Company’s behalf and is authorized to continue to acquire additional acreage within the proximity of the originally-acquired leases. This program differs from other arrangements where the Company may purchase specific leases in one-time, single closing transactions. In 2008, the Company paid a total of $815,100 related to previously acquired leasehold interests. In 2009, the Company paid a total of $501,603 related to previously acquired leasehold interests. In 2010, the Company paid a total of $5,000 related to previously acquired leasehold interests. Because each lessor separately negotiates its own desired royalty, SFE’s over-riding royalty interest varies from lease to lease. The Company is receiving a net revenue interest ranging from 80.25% to 82.5% net revenue interest in the acquired leases, which is net of royalties and overriding royalties. SFE’s president is J.R. Reger, the brother of the Company’s CEO, Michael Reger. J.R. Reger is also a shareholder in the Company.

The Company has also purchased leasehold interests from Montana Oil Properties (“MOP”). In 2008, the Company purchased leasehold interests from MOP for a total consideration of approximately $5,160,824. In 2009, the Company paid MOP a total of $63,234 related to previously acquired leasehold interests. In July 2010, the Company paid MOP a total of $269,821 for leases and reimbursement costs pertaining to two separate wells in Mountrail County, North Dakota. MOP is controlled by Mr. Tom Ryan and Mr. Steven Reger, both are relatives of the Company’s Chief Executive Officer, Michael Reger.

The Company has also purchased leasehold interests from Gallatin Resources, LLC (“Gallatin”). In 2008, the Company purchased leasehold interests from Gallatin for a total consideration of approximately $22,109. In 2009, the Company paid Gallatin a total of $22,223 related to previously acquired leasehold interests. In 2010, the Company paid Gallatin a total of $15,822 related to a previously acquired leasehold interests. Carter Stewart, one of the Company’s directors, owns a 25% interest in Gallatin. Legal counsel for Gallatin informed the Company that Mr. Stewart does not have the power to control Gallatin Resources because each member of Gallatin has the right to vote on matters in proportion to their respective membership interest in the company and company matters are determined by a vote of the holders of a majority of membership interests. Further, Mr. Stewart is neither an officer nor a director of Gallatin. As such, Mr. Stewart does not have the ability to individually control company decisions for Gallatin.

The Company has a securities account with Morgan Stanley Smith Barney that is managed by Kathleen Gilbertson, a financial advisor with that firm who is the sister of the Company’s president and Director, Ryan Gilbertson.

F-23

All transactions involving related parties were approved by the Company’s Board of Directors or Audit Committee.


NOTE 8	STOCK OPTIONS/STOCK-BASED COMPENSATION AND WARRANTS

The Company’s Board of Directors approved a stock option plan in October 2006 (“2006 Stock Option Plan”) to provide incentives to employees, directors, officers, and consultants and under which 2,000,000 shares of common stock have been reserved for issuance. The options can be either incentive stock options or non-statutory stock options and are valued at the fair market value of the stock on the date of grant. The exercise price of incentive stock options may not be less than 100% of the fair market value of the stock subject to the option on the date of the grant and, in some cases, may not be less than 110% of such fair market value. The exercise price of non-statutory options may not be less than 100% of the fair market value of the stock on the date of grant.

On November 1, 2007, the Board of Directors granted 560,000 of options under this 2006 Stock Option Plan. The Company granted 500,000 options in aggregate, to members of the board and 60,000 options to one employee pursuant to an employment agreement. These options were granted at a price of $5.18 per share and the optionees were fully vested on the grant date. Of the 560,000 options, 265,963 shares had been exercised as of December 31, 2010.

The Company accounts for stock-based compensation under the provisions of FASB ASC 718-10-55. This statement requires the Company to record an expense associated with the fair value of stock-based compensation. The Company uses the Black-Scholes option valuation model to calculate stock-based compensation at the date of grant. Option pricing models require the input of highly subjective assumptions, including the expected price volatility. The Company used the simplified method to determine the expected term of the options due to the lack of sufficient historical data. Changes in these assumptions can materially affect the fair value estimate. The total fair value of the options is recognized as compensation over the vesting period. There have been no stock options granted in 2010, 2009, and 2008 under the 2006 Stock Option Plan, and all exercises of options during 2010, 2009, and 2008 related to 2007 grants.

F-24

Changes in stock options for the years ended December 31, 2010, 2009, and 2008 were as follows:


	Number of Shares		Weighted Average Exercise Price		Remaining Contractual Term (in Years)		Intrinsic Value
2008:

Beginning Balance		660,000	$	-		-		-
Granted		-		-		-		-
Exercised		260,000		3.59		-		-
Outstanding at December 31		400,000		5.18		8.8		-
Exercisable		400,000		5.18		8.8		-
Ending Vested		400,000		5.18		8.8		-
Weighted Average Fair Value of Options Granted During Year			$	-

2009:

Beginning Balance		400,000	$	-		-		-
Granted		-		-		-		-
Exercised		100,000		5.18		-		-
Outstanding at December 31		300,000		5.18		7.8		1,998,000
Exercisable		300,000		5.18		7.8		1,998,000
Ending Vested		300,000		5.18		7.8		1,998,000
Weighted Average Fair Value of Options Granted During Year			$	-

2010:

Beginning Balance		300,000	$	-		-		-
Granted		-		-		-		-
Exercised		22,314		5.18		-		-
Forfeited		11,723		5.18		-		-
Outstanding at December 31		265,963		5.18		6.8		5,859,000
Exercisable		265,963		5.18		6.8		5,859,000
Ending Vested		265,963		5.18		6.8		5,859,000
Weighted Average Fair Value of Options Granted During Year			$	-

Currently Outstanding Options


	•	No Options expired during the years ended December 31, 2010, 2009, and 2008.

	•	The Company recorded no compensation expense related to these options for the years ended December 31, 2010, 2009, and 2008. There is no further compensation expense that will be recognized in future years, relating to all options that have been granted as of December 31, 2010, because the Company recognized the entire fair value of such compensation upon vesting of the options.

	•	There were no unvested options at December 31, 2010, 2009, and 2008.

F-25

Warrants Granted February 2009

On February 27, 2009, in conjunction with the closing of the revolving credit facility (see Note 9), the Company issued CIT warrants to purchase a total of 300,000 shares of common stock exercisable at $5.00 per share. The total fair value of the warrants was calculated using the Black-Scholes valuation model based on factors present at the time the warrants were issued. The fair value of the warrants is included in Debt Issuance Costs and are being amortized over the amended term of the facility using the effective interest method. CIT exercised the warrants in January 2011.

The following assumptions were used for the Black-Scholes model:


	February 27, 2009
Risk free rates		1	%
Dividend yield		0	%
Expected volatility		96.43	%
Weighted average expected warrant life		1.5 Years

The “fair market value” at the date of issuance for the warrants issued using the formula relied upon for calculating the fair value of warrants is as follows:


Weighted average fair value per share	$	0.74
Total warrants granted		300,000
Total weighted average fair value of warrants granted	$	221,153

In January 2009, the Company’s Board of Directors adopted the 2009 Equity Incentive Plan, pursuant to which the Company may 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, the Company had issued 1,912,991 shares of common stock pursuant to the Company’s 2009 Equity Incentive Plan (See Note 6).

The table below reflects the status of warrants outstanding at December 31, 2010:


Issue Date	Common Shares	Exercise Price		Expiration Date
February 27, 2009	300,000	$	5.00		February 27, 2012

At December 31, 2010, the per-share weighted average exercise price of outstanding warrants was $5.00 per share, and the weighted average remaining contractual life was 1.2 years. All of the warrants were exercisable as of December 31, 2010. The warrants were exercised in January 2011.


NOTE 9	REVOLVING CREDIT FACILITY

In February 2009, the Company completed the closing of a revolving credit facility with CIT that provided up to a maximum principal amount of $25 million of working capital for exploration and production operations.

On May 26, 2010, the Company completed the assignment of its revolving credit facility to Macquarie from CIT. In connection with the assignment the Company and Macquarie entered into an Amended and Restated Credit Agreement governing the facility (the “Credit Facility”).

The Credit Facility provides up to a maximum principal amount of $100 million of working capital for exploration and production operations. The borrowing base of funds available under the Credit Facility is re-determined semi-annually based upon the net present value, discounted at 10% per annum, of the future net revenues expected to accrue from its interests in proved reserves estimated to be produced from its crude oil and natural gas properties. $25 million of financing is currently available under the Credit Facility. The Credit Facility terminates on May 26, 2014. The Company had no borrowings under the Credit Facility at December 31, 2010 and 2009.

F-26

The Company has the option to designate the reference rate of interest for each specific borrowing under the Credit Facility as amounts are advanced. Borrowings based upon the London interbank offering rate (“LIBOR”) will bear interest at a rate equal LIBOR plus a spread ranging from 2.5% to 3.25% depending on the percentage of borrowings base that is currently advanced. Any borrowings not designated as being based upon LIBOR will bear interest at a rate equal to the greater of (a) the current prime rate published by the Wall Street Journal, or (b) the current one month LIBOR rate plus 1.0%, plus in either case a spread ranging from 2% to 2.5%, depending on the percentage of borrowing base that is currently advanced. The Company has the option to designate either pricing mechanism. Payments are due under the Credit Facility in arrears, in the case of a loan based on LIBOR on the last day of the specified interest period and in the case of all other loans on the last day of each March, June, September and December. All outstanding principal is due and payable upon termination of the Credit Facility.

The applicable interest rate increases under the Credit Facility and the lenders may accelerate payments under the Credit Facility, or call all obligations due under certain circumstances, upon an event of default. The Credit Facility references various events constituting a default on the Credit Facility, including, but not limited to, failure to pay interest on any loan under the Credit Facility, any material violation of any representation or warranty under the Amended and Restated Credit Agreement, failure to observe or perform certain covenants, conditions or agreements under the Amended and Restated Credit Agreement, a change in control of the Company, default under any other material indebtedness the Company might have, bankruptcy and similar proceedings and failure to pay disbursements from lines of credit issued under the Credit Facility. The Company was not in default on the Credit Facility as of December 31, 2010, and is not expected to be in default in the future.

The Credit Facility requires that the Company enter into swap agreements with Macquarie for each month of the thirty-six (36) month period following the date on which each such swap agreement is executed, the notional volumes for which when aggregated with other commodity swap agreements and additional fixed-price physical off-take contracts then in effect, as of the date such swap agreement is executed, is not less than 50%, nor exceeds 90%, of the reasonably anticipated projected production from the Company’s proved developed producing reserves, as defined at the time of the agreement. The Company entered into swap agreements as required at the time, and presently there are no material hedging requirements imposed by Macquarie.

All of the Company’s obligations under the Credit Facility and the swap agreements with Macquarie are secured by a first priority security interest in any and all assets of the Company.


NOTE 10	ASSET RETIREMENT OBLIGATION

The Company has asset retirement obligations associated with the future plugging and abandonment of proved properties and related facilities. Under the provisions of FASB ASC 410-20-25, the fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred and a corresponding increase in the carrying amount of the related long lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. The Company has no assets that are legally restricted for purposes of settling asset retirement obligations.

The following table summarizes the company’s asset retirement obligation transactions recorded in accordance with the provisions of FASB ASC 410-20-25 during the year ended December 31, 2010 and 2009.


	Year Ended December 31,
	2010			2009
Beginning Asset Retirement Obligation	$	206,741		$	61,437
Liabilities Incurred for New Wells Placed in Production		232,258			137,222
Liabilities Settled		(1,428	)		-
Accretion of Discount on Asset Retirement Obligations		21,755			8,082
Ending Asset Retirement Obligation	$	459,326			206,741

F-27


NOTE 11	INCOME TAXES

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

The income tax expense (benefit) for the year ended December 31, 2010, 2009, and 2008 consists of the following:


	2010		2009		2008 Adjusted
Current Income Taxes	$	-	$	-	$	-
Deferred Income Taxes
Federal		3,625,000		1,215,000		(680,000	)
State		794,000		251,000		(150,000	)
Total Expense (Benefit)	$	4,419,000	$	1,466,000	$	(830,000	)

The following is a reconciliation of the reported amount of income tax expense (benefit) for the years ended December 31, 2010, 2009, and 2008 to the amount of income tax expenses that would result from applying the statutory rate to pretax income.

Reconciliation of reported amount of income tax expense (benefit):


	2010			2009			2008 Adjusted
Income Before Taxes and NOL	$	11,336,300		$	4,264,952		$	1,594,340
Federal Statutory Rate		X 34	%		X 34	%		x 34	%
Taxes Computed at Federal Statutory Rates		3,854,000			1,450,000			540,000
State Taxes, Net of Federal Taxes		524,000			295,000			110,000
Effects of:
Other		41,000			(279,000	)		(7,659	)
Change in Valuation		-			-			(1,472,341	)
Reported Provision (Benefit)	$	4,419,000		$	1,466,000		$	(830,000	)

At December 31, 2010, 2009 and 2008, the Company has a net operating loss carryforward for Federal income tax purposes of $62,100,000, $18,494,000 and $9,348,000, respectively, which expires in varying amounts during the tax years 2027, 2028 and 2029.

F-28

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


	Year Ended December 31,
	2010			2009
Deferred Tax Assets (Liability)
Current:
Share Based Compensation (Options)	$	600,000		$	774,000
Share Based Compensation (Restricted Stock)		127,000			(91,000	)
Unrealized Investment Losses		4,414,000			1,231000
Accrued Payroll		-			288,000
Other		(41,000	)		(145,000	)
Current		5,100,000			2,057,000

Non-Current:
Net Operating Loss Carryforwards (NOLs)		23,987,000			7,583,000
Fixed Assets		(8,341,000	)		(2,646,000	)
Dry Well Write Off		(36,000	)		(36,000	)
Unrealized Investment Losses		1,939,000			395,000
Depletion		7,532,000			1,562,000
Intangible Drilling Costs		(34,432,000	)		(7,955,000	)
Sale of Land Lease Rights		155,000			117,000
Other		29,000			58,000
Non-Current		(9,167,000	)		(922,000	)

Total Deferred Tax Assets (Liabilities)		(4,067,000	)		1,135,000
Less: Valuation Allowance		-			-

Net Deferred Tax Asset (Liability)	$	(4,067,000	)		1,135,000

In June 2006, FASB issued FASB ASC 740-10-05-6. The Company adopted FASB ASC 740-10-05-6 on January 1, 2007. Under FASB ASC 740-10-05-6, tax benefits are recognized only for tax positions that are more likely than not to be sustained upon examination by tax authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50 percent likely to be realized upon ultimate settlement. Unrecognized tax benefits are tax benefits claimed in the Company’s tax returns that do not meet these recognition and measurement standards.

Upon the adoption of FASB ASC 740-10-05-6, the Company had no liabilities for unrecognized tax benefits and, as such, the adoption had no impact on its financial statements, and the Company has recorded no additional interest or penalties. The adoption of FASB ASC 740-10-05-6 did not impact the Company’s effective tax rates.

The Company’s policy is to recognize potential interest and penalties accrued related to unrecognized tax benefits within income tax expense. For the years ended December 31, 2010, 2009 and 2008, the Company did not recognize any interest or penalties in its Statement of Operations, nor did it have any interest or penalties accrued in its Balance Sheet at December 31, 2010 and 2009 relating to unrecognized benefits.

The tax years 2010, 2009, 2008, 2007 and 2006 remain open to examination for federal income tax purposes and by the other major taxing jurisdictions to which the Company is subject.

F-29


NOTE 12	OPERATING LEASES

Vehicles

The Company leases vehicles under noncancelable operating leases. Total lease expense under the agreements was approximately $58,000, $52,000 and $31,000 for the years ended December 31, 2010, 2009, and 2008, respectively.

Minimum future lease payments under these vehicle leases are as follows:


Year Ended December 31,	Amount
2011	$	59,951
2012	$	50,114
2013	$	28,765
Total	$	138,830

Building

Effective February 2008, the Company entered into an operating lease agreement to lease 3,044 square feet of office space. The lease requires initial gross monthly lease payments of $11,415. The monthly payments increase by 4% on each anniversary date. The lease expires in December 2012. Total rent expense under the agreement was approximately $148,000, $142,000 and $114,000 for the years ended December 31, 2010, 2009, and 2008, respectively.

The Company has prepaid $34,245, the last three months rent. Minimum future lease payments under the building lease are as follows:


Year Ended December 31,	Amount
2011	$	154,087
2012	$	160,236
Total	$	314,323

The Company received $91,320 of landlord incentives under the lease agreement. The Company has recorded a deferred rent liability for this amount that is being amortized over the term of the lease.

Prior to this lease the Company was paying $1,250 on a month-to-month lease.


NOTE 13	FAIR VALUE

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

Level 1 - Quoted prices in active markets for identical assets or liabilities.

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

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

The following schedule summarizes the valuation of financial instruments measured at fair value on a recurring basis in the balance sheet as of December 31, 2010 and 2009.


	Fair Value Measurements at December 31, 2010 Using
	Quoted Prices In Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Current Derivative Liabilities	$	-	$	(11,145,318	)	$	-
Non-Current Derivative Liabilities	$	-	$	(5,022,657	)	$	-
Short-Term Investments (See Note 3)	$	39,726,700	$	-		$	-
Total	$	39,726,700	$	(16,167,975	)	$	-


	Fair Value Measurements at December 31, 2009 Using
	Quoted Prices In Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Current Derivative Liabilities	$	-	$	(1,320,679	)	$	-
Non-Current Derivative Liabilities	$	-	$	(1,459,374	)	$	-
Short-Term Investments (See Note 3)	$	23,085,120	$	-		$	1,818,356
Total	$	23,085,120	$	(2,780,053	)	$	1,818,356

Level 1 assets consist of US Treasury Notes, the fair value of these treasuries is based on quoted market prices.

Level 2 liabilities consist of derivative liabilities (see Note 15). Under FASB ASC 820-10-55, the fair value of the Company’s derivative financial instruments is determined based on spot prices and the notional quantities. The fair value of all derivative contracts is reflected on the balance sheet. The current derivative liability amounts represent the fair values expected to be included in the results of operations for the subsequent year.

Level 3 assets consist of municipal bonds and floating rate preferred stock with an auction reset feature (“auction rate securities” or ARS). The underlying assets for the municipal bonds are student loans which are substantially backed by the federal government. Auction-rate securities are long-term floating rate bonds or floating rate perpetual preferred stock tied to short-term interest rates. After the initial issuance of the securities, the interest rate on the securities is reset periodically, at intervals established at the time of issuance (primarily every twenty-eight days), based on market demand for a reset period. Auction-rate securities are bought and sold in the marketplace through a competitive bidding process often referred to as a “Dutch auction”. If there is insufficient interest in the securities at the time of an auction, the auction may not be completed and the rates may be reset to pre-determined “penalty” or “maximum” rates based on mathematical formulas in accordance with each security’s prospectus.

The following table provides a reconciliation of the beginning and ending balances for the assets measured at fair value using significant unobservable inputs (Level 3):

F-31


	Fair Value Measurements at Reporting Date Using Significant Unobservable Inputs (Level 3) Level 3 Financial Assets
Balance at January 1, 2009	$	2,416,369
Sales		(800,000	)
Unrealized Gain Included in Other Comprehensive Income (Loss)		201,987
Balance at December 31, 2009	$	1,818,356
Sales		(2,025,003	)
Unrealized Gain Included in Other Comprehensive Income (Loss)		206,787
Realized Loss on Sales		(140	)
Balance at December 31, 2010	$	-

The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may effect the valuation of the nonfinancial assets and liabilities and their placement in the fair value hierarchy levels. The fair value of the Company’s asset retirement obligations are determined using discounted cash flow methodologies based on inputs that are not readily available in public markets. The fair value of the asset retirement obligations is reflected on the balance sheet as follows.


	Fair Value Measurements at December 31, 2010 Using
Description	December 31, 2010			Quoted Prices In Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Other Non-current Liabilities	$	(459,326	)	$	-	$	-	$	(459,326	)
Total	$	(459,326	)	$	-	$	-	$	(459,326	)


	Fair Value Measurements at December 31, 2009 Using
Description	December 31, 2009			Quoted Prices In Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Other Non-current Liabilities	$	(206,741	)	$	-	$	-	$	(206,741	)
Total	$	(206,741	)	$	-	$	-	$	(206,741	)

See Note 10 for a rollforward of the Asset Retirement Obligation.

NOTE 14 FINANCIAL INSTRUMENTS

The Company’s non-derivative financial instruments include cash and cash equivalents, accounts receivable, short term investments, accounts payable and line of credit. The carrying amount of cash and cash equivalents, accounts receivable, accounts payable, and line of credit approximate fair value because of their immediate or short-term maturities.

F-32

The Company’s accounts receivable relate to crude oil and natural gas sold to various industry companies. Credit terms, typical of industry standards, are of a short-term nature and the Company does not require collateral. Management believes the Company’s accounts receivable at December 31, 2010 and 2009 do not represent significant credit risks as they are dispersed across many counterparties.

NOTE 15 DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT

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

Crude Oil Derivative Contracts Cash-flow Hedges

Historically, all derivative positions that qualified for hedge accounting were designated on the date the Company entered into the contract as a hedge against the variability in cash flows associated with the forecasted sale of future crude oil production. The cash flow hedges were valued at the end of each period and adjustments to the fair value of the contract prior to settlement were recorded on the statement of stockholders’ equity as other comprehensive income. Upon settlement, the gain (loss) on the cash flow hedge was recorded as an increase or decrease in revenue on the statement of operations. The Company reports average crude oil and natural gas prices and revenues including the net results of hedging activities.

On November 1, 2009, due to the volatility of price differentials in the Williston Basin, the Company de-designated all derivates that were previously classified as cash flow hedges and, in addition, the Company has elected not to designate any subsequent derivative contracts as cash flow hedges under FASB ASC 815-20-25. Beginning on November 1, 2009, all derivative positions are carried at their fair value on the balance sheet and are marked-to-market at the end of each period. Any realized gains and losses are recorded to Gain (Loss) on Settled Derivatives and unrealized gains or losses are recorded to Mark-to-Market of Derivative Instruments on the Statement of Operations rather than as a component of other comprehensive income (loss) or other Income (expense).

FASB ASC 815-20-25 requires the fair value disclosure of derivative instruments be presented on a gross basis, even when those instruments are subject to a master netting arrangement and qualify for net presentations on the balance sheet in accordance with ASC 210-20. The Company has a master netting agreement on each of the individual crude oil contracts and therefore the current asset and liability are netted on the balance sheet and the non-current asset and liability are netted on the balance sheet.

The net mark-to-market loss on the Company’s remaining swaps that qualified for cash flow hedge accounting at the date the decision was made to discontinue hedge accounting totals $1,259,085 and $2,416,639 as of December 31, 2010 and 2009. The Company has recorded that amount as accumulated other comprehensive income in stockholders’ equity and the entire amount will be amortized into revenues as the original forecasted hedged crude oil production occurs in the following periods.


For the Quarter Ended	Commodity Derivatives
March 31, 2011	$	270,150
June 30, 2011		283,800
September 30, 2011		295,950
December 31, 2011		307,875
March 31, 2012		101,310
Total	$	1,259,085

The Company realized a settled derivative loss of $469,607 and $624,541 and maintained a mark-to-market value of and unrealized loss of $14,545,477 and $363,414 on derivative instruments for the years ended December 31, 2010 and 2009. The Company realized a settled derivative gain of $778,885 for the year ended December 31, 2008.

F-33

The following table reflects open commodity derivative contracts as of December 31, 2010, the associated volumes and the corresponding weighted average NYMEX reference price.


Settlement Period	Oil (Barrels)		Fixed Price		Weighted Avg NYMEX Reference Price
Oil Swaps
01/01/11 – 02/29/12		27,000		51.25		93.81
01/01/11 – 12/31/11		18,000		66.15		93.76
01/01/11 12/31/11		48,000		82.60		93.76
01/01/11 12/31/11		18,000		84.25		93.76
01/01/11 12/31/11		54,996		80.90		93.76
01/01/11 12/31/11		101,000		88.00		93.66
01/01/11 06/30/12		246,504		80.00		93.73
01/01/11 06/30/12		545,500		81.50		93.97
01/01/11 06/30/12		303,000		85.50		93.51

As of December 31, 2010, the Company had a total hedged volume of 1,362,000 barrels at a weighted average price of approximately $81.85.

The following table reflects the weighted average price of open commodity derivative contracts as of December 31, 2010, by year with associated volumes.


Weighted Average Price Of Open Commodity Swap Contracts
Year	Volumes (Bbl)		Weighted Average Price
2011		963,000	$	82.05
2012		399,000		81.36

At December 31, 2010 and 2009, the Company had derivative financial instruments under FASB ASC 815-20-25 recorded on the consolidated balance sheet as set forth below:


Type of Contract	Balance Sheet Location	December 31, 2010 Estimated Fair Value			December 31, 2009 Estimated Fair Value
Derivatives Designated as Hedging Instruments
Derivative Assets:
Oil Contracts	Other current assets	$	-		$	96,163
Oil Contracts	Other non-current assets		-			-
Total Derivative Assets		$	-		$	96,163

Derivative Liabilities:
Oil Contracts	Other current liabilities	$	(11,145,318	)	$	(1,402,910	)
Oil Contracts	Other non-current liabilities		(5,022,657	)		(1,473,306	)
Total Derivative Liabilities		$	(16,167,975	)	$	(2,876,216	)

F-34

The following disclosures are applicable to our financial statements, as of December 31, 2010 and December 31, 2009:


	Location of Gain /(Loss) for Effective and Ineffective Portion of Derivative in Income	Amount of Gain/(Loss) Reclassified from AOCI into Income


Derivative Type		Year Ended December 31, 2010			Year Ended December 31, 2009
Commodity-Cash Flow	Gain (Loss) on Settled Derivatives	$	(1,157,554	)	$	(363,414	)

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

NOTE 16 EARNINGS PER SHARE

The following is a reconciliation of the numerator and denominator used to calculate basic earnings per share and diluted earnings per share for the years ended December 31, 2010, 2009, and 2008:


	2010						2009						2008
	Net Income		Shares		Per Share		Net Income		Shares		Per Share		Net Income Adjusted		Shares		Per Share
Basic EPS	$	6,917,300		50,387,203	$	0.14	$	2,798,952		36,705,267	$	0.08	$	2,424,340		31,920,747	$	0.08
Dilutive effect of options		-		391,042				-		171,803				-		732,805
Diluted EPS	$	6,917,300		50,778,245	$	0.14	$	2,798,952		36,877,070	$	0.08	$	2,424,340		32,653,552	$	0.07

For the years ended December 31, 2009 and 2008, options and warrants to purchase 21,678 and 7,476 shares of common stock were not considered in calculating diluted earnings per share because the exercise prices were greater than the average market price of common shares during the year and, therefore, the effect would be anti-dilutive.

NOTE 17 COMPREHENSIVE INCOME

The Company follows the provisions of FASB ASC 220-10-55 which establishes standards for reporting comprehensive income. In addition to net income, comprehensive income includes all changes in equity during a period, except those resulting from investments and distributions to shareholders of the Company.

F-35

For the periods indicated, comprehensive income (loss) consisted of the following:


	Year Ended December 31,
	2010		2009			2008 Adjusted
Net Income (Loss)	$	6,917,300	$	2,798,952		$	2,424,340
Unrealized losses on Short-term Investments (net of tax of $349,000, $290,000 and $168,000 at December 31, 2010, 2009 and 2008)		553,135		(486,207	)		(240,774	)
Net unrealized losses on hedges (Net of tax of $446,000 and $933,000 at December 31, 2010 and 2009)		711,554		(1,483,639	)		-
Other Comprehensive income (loss) net	$	8,181,989	$	829,106		$	2,183,566

NOTE 18 EMPLOYEE BENEFIT PLANS

In 2009, the Company adopted a defined contribution 401(k) plan for substantially all of its employees. The plan provides for Company matching of employee contributions to the plan, at the Company’s discretion. During 2010 and 2009, the Company provided a match contribution equal to 100% of an eligible employee’s deferral contribution, up to 6% of the employee’s earnings up to $16,500. The Company contributed approximately $80,000 and $66,400 to the 401(k) plan for the years ended December 31, 2010 and 2009.

NOTE 19 SUBSEQUENT EVENTS

In February 2009, the Company entered into a revolving credit facility with CIT, in which CIT was issued 300,000 warrants in connection with the transaction. In January 2011, CIT exercised the 300,000 warrants at a price of $5.00 per share.

In January 2011, the Company entered into a commodity swap contract. The crude oil swap contract is for 376,000 barrels of crude oil with settlement periods between January 2012 and December 2012. The price on the contract is fixed at $95.15 per barrel.

In January 2011, the Company entered into a costless collar (purchased put options and written call options). The costless collars are used to establish floor and ceiling prices on anticipated crude oil and natural gas production. There were no net premiums paid or received by the Company related to the costless collar agreement. The Company purchased put options at $85.00 per barrel and call options at $101.75 per barrel on 508,000 barrels of crude oil. The costless collar amounts settle between February 2011 and December 2011.

In February 2011, the Company entered into a commodity swap contract. The crude oil swap contract is for 20,000 barrels of crude oil per month for the months of January 2012 through December 2012. The price on the contract is fixed at $100.00 per barrel.

The following table reflects the weighted average price of open commodity swap contracts as of March 1, 2011, by year with associated volumes.


Weighted Average Price Of Open Commodity Swap Contracts
Year	Volumes (Bbl)		Weighted Average Price
2011		774,000	$	81.93
2012		1,015,000	$	90.87

As of March 1, 2011, the Company had a total hedged volume on open commodity swaps of 1,789,000 barrels at a weighted average price of approximately $87.00, as well as 451,000 barrels of crude oil collared between $85.00 and $101.75.

F-36

SUPPLEMENTAL OIL AND GAS INFORMATION
(UNAUDITED)

Oil and Natural Gas Exploration and Production Activities

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

Costs Incurred and Capitalized Costs

The costs incurred in crude oil and natural gas acquisition, exploration and development activities are highlighted in the table below. As the Company expanded the geographic area of its acreage acquisition program in 2010, property acquisitions that the company deemed proven were categorized as proven property acquisitions. All other acquisition costs were categorized as unproved property acquisitions. For 2009 and 2008, all acreage acquisition costs were categorized as proved property acquisitions as the Company determined that all acreage acquisitions in those years were in proven areas at the time they were acquired.


	Year Ended December 31,
	2010		2009		2008
Costs Incurred for the Year:
Proved Property Acquisition	$	2,236,167	$	30,800,883	$	30,508,139
Unproved Property Acquisition		72,308,719		-		-
Development		123,933,003		18,739,905		9,165,188
Total	$	198,477,889	$	49,540,788	$	39,673,327


	Year Ended December 31,
	2010		2009		2008		Prior Years
Property Acquisition	$	63,636,650	$	16,061,848	$	24,938,734	$	5,147,236
Drilling		26,350,695		-		-
Total	$	89,987,345	$	16,061,848	$	24,938,734	$	5,147,236

F-37

Oil and Natural Gas Reserves and Related Financial Data

Information with respect to the Company’s crude oil and natural gas producing activities is presented in the following tables. Reserve quantities, as well as certain information regarding future production and discounted cash flows, were determined by Ryder Scott Company, independent petroleum consultants based on information provided by the Company.

Oil and Natural Gas Reserve Data

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


	Natural Gas (MCF)			Oil (BBLS)
Proved Developed and Undeveloped Reserves at December 31, 2008		216,451			727,665

Revisions of Previous Estimates		(27,820	)		(93,819	)
Extensions, Discoveries and Other Additions		1,619,597			5,456,261
Production		(47,305	)		(274,528	)

Proved Developed and Undeveloped Reserves at December 31, 2009		1,760,923			5,815,579

Revisions of Previous Estimates		625,103			514,899
Extensions, Discoveries and Other Additions		8,298,347			8,513,064
Production		(234,411	)		(849,845	)

Proved Developed and Undeveloped Reserves at December 31, 2010		10,449,962			13,993,697

Proved Developed Reserves at December 31, 2008		216,451			727,665
Proved Developed Reserves at December 31, 2009		727,237			2,247,718
Proved Developed Reserves at December 31, 2010		3,513,427			5,840,745

Proved reserves are estimated quantities of crude oil and natural gas, which geological and engineering data indicate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are included for reserves for which there is a high degree of confidence in their recoverability and they are scheduled to be drilled within the next five years.

F-38

Standardized Measure of Discounted Future Net Cash Inflows and Changes Therein

The following table presents a standardized measure of discounted future net cash flows relating to proved crude oil and natural gas reserves and the changes in standardized measure of discounted future net cash flows relating proved crude oil and natural gas were prepared in accordance with the provisions of ASC 932-235-555 (formerly SFAS 69). Future cash inflows were computed by applying average prices of crude oil and natural gas for the last 12 months as of December 31, 2010, December 31, 2009 and December 31, 2008 to estimated future production. Future production and development costs were computed by estimating the expenditures to be incurred in developing and producing the proved crude oil and natural gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. Future income tax expenses were calculated by applying appropriate year-end tax rates to future pretax cash flows relating to proved crude oil and natural gas reserves, less the tax basis of properties involved and tax credits and loss carryforwards relating to crude oil and natural gas producing activities. Future net cash flows are discounted at the rate of 10% annually to derive the standardized measure of discounted future cash flows. Actual future cash inflows may vary considerably, and the standardized measure does not necessarily represent the fair value of the Company’s crude oil and natural gas reserves.


	Year Ended December 31,
	2010			2009			2008
Future Cash Inflows	$	1,038,703,438		$	315,142,688		$	29,342,354
Future Production Costs		(271,843,571	)		(105,982,773	)		(8,719,621	)
Future Development Costs		(161,853,922	)		(54,011,133	)		(1,321,948	)
Future Income Tax Expense		(199,197,425	)		(43,761,765	)		-
Future Net Cash Inflows		405,808,520			111,387,017			19,300,785

10% Annual Discount for Estimated Timing of Cash Flows		(195,195,729	)		(43,580,456	)		(7,514,731	)

Standardized Measure of Discounted Future Net Cash Flows	$	210,612,791		$	67,806,561		$	11,786,054

The twelve month average prices for the year ended December 31, 2010, December 31, 2009 and year-end spot prices at December 31, 2008 were adjusted to reflect applicable transportation and quality differentials on a well-by-well basis to arrive at realized sales prices used to estimate the Company’s reserves. The prices for the Company’s reserve estimates were as follows:


	Natural Gas MCF		Oil Bbl
December 31, 2010 (Spot Price)	$	5.04	$	70.46
December 31, 2009 (Average)	$	3.93	$	53.00
December 31, 2008 (Average)	$	5.80	$	38.60

F-39

Changes in the Standardized Measure of Discounted Future Net Cash Flows at 10% per annum follow:


	Year Ended December 31,
	2010			2009			2008
Beginning of Period	$	67,806,561		$	11,786,054		$	-
Sales of Oil and Natural Gas Produced, Net of Production Costs		(50,721,827	)		(13,116,475	)		(3,268,858	)
Extensions and Discoveries		185,403,280			74,946,755			19,967,182
Previously Estimated Development Cost Incurred During the Period		3,350,016			1,321,948			-
Net Change of Prices and Production Costs		88,564,348			4,352,381			(3,660,754	)
Change in Future Development Costs		(3,003,304	)		-			(1,251,516	)
Revisions of Quantity and Timing Estimates		(3,237,346	)		(1,650,626	)		-
Accretion of Discount		8,781,249			1,178,605			-
Change in Income Taxes		(104,428,302	)		(20,005,322	)		-
Purchase of Reserves in Place		-			9,579,951			-
Other		(1,431,520	)		(586,710	)		-
End of Period	$	191,083,155		$	67,806,561		$	11,786,054

F-40

QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)

Quarterly data for the years end December 31, 2010, 2009, and 2008 is as follows:


	Quarter Ended
	March 31,			June 30,			September 30,			December 31,
2010
Revenue	$	7,221,514		$	16,231,773		$	9,883,821		$	11,221,992
Expenses		4,596,936			6,133,565			8,159,485			14,163,826
Income from Operations		2,624,578			10,098,208			1,724,336			(2,941,834	)
Other Income (Expense)		(87,948	)		(144,342	)		(117,110	)		180,412
Income Tax Provision		977,000			3,833,000			620,000			(1,011,000	)
Net Income		1,559,630			6,120,866			987,226			(1,750,422	)
Net Income Per Common Share – Basic		0.04			0.12			0.02			(0.03	)
Net Income Per Common Share – Diluted		0.04			0.12			0.02			(0.03	)

	Quarter Ended
	March 31,			June 30,			September 30,
	Adjusted **			Adjusted **			Adjusted **			December 31,
2009
Revenue	$	658,268		$	2,275,084		$	4,855,972		$	6,432,175
Expenses		1,047,614			1,437,445			2,530,315			5,077,164
Income (Loss) from Operations		(389,346	)		837,639			2,325,657			1,355,011
Other Income (Expense)		(43,527	)		(139,243	)		321,589			(2,828	)
Income Tax Provision (Benefit)		(174,000	)		280,000			1,059,000			301,000
Net Income (Loss)		(258,873	)		418,396			1,588,246			1,051,183
Net Income (Loss) Per Common Share – Basic		(0.01	)		0.01			0.04			0.03
Net Income (Loss) Per Common Share – Diluted		(0.01	)		0.01			0.04			0.03

	Quarter Ended
	March 31,			June 30,			September 30,			December 31,
	Adjusted**			Adjusted**			Adjusted**			Adjusted**
2008
Revenue	$	287,029		$	764,528		$	1,362,655		$	1,907,667
Expenses		570,575			548,849			600,213			1,391,793
Income (Loss) from Operations		(283,546	)		215,679			762,442			515,874
Other Income		96,269			95,424			155,121			37,077
Income Tax Provision (Benefit)		-			-			-			(830,000	)
Net Income (Loss)		(187,277	)		311,103			917,563			1,382,951
Net Income (Loss) Per Common Share – Basic and Diluted		(0.01	)		0.01			0.03			0.03

** In 2009, the Company changed its method of accounting for drilling costs. As required by generally accepted accounting principles the impact of the change in accounting has been applied retrospectively to all periods presented.

F-41

Attached files

NORTHERN OIL & GAS, INC. Reports

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