Northern Oil and Gas, Inc. (NOG, NYSE)
Industry: Oil & Gas E&P
Annual report, fiscal year 2009


# NORTHERN OIL & GAS, INC.

FORM 10-K
(Annual Report)

# Filed 03/08/10 for the Period Ending 12/31/09

Address 315 MANITOBA AVE

WAYZATA, MN 55391

Telephone 952-476-9800

CIK 0001104485

Symbol NOG

SIC Code 1311 - Crude Petroleum and Natural Gas

Fiscal Year 12/31



# UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549

FORM 10-K

(Mark One)

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

# For the fiscal year ended December 31, 2009
or

# ☑ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ___ to ___

Commission File No. - 000-33999

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

Nevada
(State or Other Jurisdiction of Incorporation or Organization)

95-3848122
(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

Common Stock, $0.001 par value

Name of Each Exchange On Which Registered

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



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 T No £

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T ( \( §22.405 \)  of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files. Yes £ No £

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

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

Large Accelerated Filer £

Accelerated Filer T

Non-Accelerated Filer £

Smaller Reporting Company £

(Do not check if a smaller reporting company)

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

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 $192,730,733.

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, 2010, the registrant had 43,911,044 shares of common stock issued and outstanding.

## DOCUMENTS INCORPORATED BY REFERENCE

Portions of the proxy statement related to the registrant’s 2010 Annual Meeting of Stockholders are incorporated by reference into Part III of this report.

## CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

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

From time to time, our management or persons acting on our behalf may make forward-looking statements to inform existing and potential security holders about our company. All statements other than statements of historical facts included in this report regarding our financial position, business strategy, plans and objectives of management for future operations, industry conditions, and indebtedness covenant compliance are forward-looking



statements. When used in this report, forward-looking statements are generally accompanied by terms or phrases such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “target,” “plan,” “intend,” “seek,” “goal,” “will,” “should,” “may” or other words and similar expressions that convey the uncertainty of future events or outcomes. Items contemplating or making assumptions about, actual or potential future sales, market size, collaborations, and trends or operating results also constitute such forward-looking statements.

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

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

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



## NORTHERN OIL AND GAS, INC.

## TABLE OF CONTENTS

Page

Part I

Item 1. Business 2
Item 1A. Risk Factors 8
Item 1B. Unresolved Staff Comments 17
Item 2. Properties 17
Item 3. Legal Proceedings 21
Item 4. Reserved 21

Part II

Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 21
Item 6. Selected Financial Data 23
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 25
Item 7A. Quantitative and Qualitative Disclosures About Market Risk 31
Item 8. Financial Statements and Supplementary Data 32
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure 32
Item 9A. Controls and Procedures 32
Item 9B. Other Information 34

Part III

Item 10. Directors, Executive Officers and Corporate Governance 35
Item 11. Executive Compensation 35
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 36
Item 13. Certain Relationships and Related Transactions, and Director Independence 36
Item 14. Principal Accountant Fees and Services 36

Part IV

Item 15. Exhibits and Financial Statement Schedules 37

Signatures

40

Index to Financial Statements

F-1



# NORTHERN OIL AND GAS, INC.
2009 ANNUAL REPORT ON FORM 10-K

# 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 company’s 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. The financial statements presented in our company’s December 31, 2006, Form 10-KSB report were the historical financial statements of Kentex Petroleum, Inc., the predecessor company. Additional material terms of the Merger are detailed in our company’s Current Report on Form 8-K filed with the SEC on December 19, 2006. Following the Merger, our main business focus has been directed to oil and gas exploration and development. Unless specifically stated otherwise, our primary operations are now those formerly operated by Northern as well as other business activities since March 2007.

On March 17, 2008 our company received an approval letter to begin trading on the American Stock Exchange (the “AMEX”). Our common stock commenced trading on the AMEX on March 26, 2008 under the symbol “NOG.” Our common stock commenced trading on the floor of the NYSE on the NYSE Amex Equities Market platform upon completion of NYSE Euronext’s acquisition of the American Stock Exchange.

## Business

We are a growth-oriented independent energy company engaged in the acquisition, exploration, exploitation and development of oil and natural gas properties, and have focused our activities primarily on projects based in the Rocky Mountain Region of the United States, specifically the Bakken and Three Forks/Sanish formations within the Williston Basin. 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 oil in the Williston Basin region in the fourth fiscal quarter of 2007. As of March 1, 2010, we owned working interests in 188 successful discoveries, consisting of 185 targeting the Bakken/Three Forks formation and three targeting a Red River structure.

As an exploration company, our business strategy is to identify and exploit repeatable and scalable resource plays that can be quickly developed and at low costs. We also 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, specifically in the Williston Basin, in a nimble and efficient fashion.

We are focused on maintaining a low overhead structure. We believe we are in a position to most efficiently exploit and identify high production oil and 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, 2009. At year-end, we had completed drilling on approximately 10% of our Bakken prospective acreage inventory assuming 640-acre spacing units. 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.

The tables below summarize our estimated proved reserves as of December 31, 2009 based upon reports prepared by Ryder Scott Company, LP (“Ryder Scott”), an independent reservoir engineering firm. Ryder Scott is one of the largest reservoir-evaluation consulting firms and evaluates oil and gas properties and independently certifies petroleum reserves quantities for various clients throughout the United States and internationally.

Ryder Scott prepared two separate reserve reports valuing our proved reserves at December 31, 2009. 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 oil and 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, 2009.

SEC Pricing Proved Reserves  $ (1) \) 

<table><tr><td></td><td>Crude Oil (barrels)</td><td>Natural Gas (cubic feet)</td><td>Total (barrels of oil equivalent)  \( {}^{(2)} \)</td><td>Pre-Tax PV10% Value  \( {}^{(3)} \)</td></tr><tr><td>PDP Properties  \( {}^{(4)} \)</td><td>1,647,031</td><td>513,112</td><td>1,732,550</td><td>$ 37,784,555</td></tr><tr><td>PDNP Properties  \( {}^{(5)} \)</td><td>600,687</td><td>214,125</td><td>636,375</td><td>$ 12,795,237</td></tr><tr><td>PUD Properties  \( {}^{(6)} \)</td><td>3,567,861</td><td>1,033,686</td><td>3,740,141</td><td>$ 37,232,700</td></tr><tr><td></td><td>5,815,579</td><td>1,760,923</td><td>6,109,066</td><td>$ 87,812,492</td></tr></table>

Sensitivity Case Proved Reserves  $ (1) \) 

<table><tr><td></td><td>Crude Oil (barrels)</td><td>Natural Gas (cubic feet)</td><td>Total (barrels of oil equivalent)  \( {}^{(2)} \)</td><td>Pre-Tax PV10% Value  \( {}^{(3)} \)</td></tr><tr><td>PDP Properties  \( {}^{(4)} \)</td><td>1,730,728</td><td>529,657</td><td>1,819,004</td><td>$ 54,303,781</td></tr><tr><td>PDNP Properties  \( {}^{(5)} \)</td><td>630,542</td><td>224,383</td><td>667,939</td><td>$ 19,378,670</td></tr><tr><td>PUD Properties  \( {}^{(6)} \)</td><td>7,447,783</td><td>3,508,210</td><td>8,032,485</td><td>$ 93,901,002</td></tr><tr><td></td><td>9,809,053</td><td>4,262,250</td><td>10,519,428</td><td>$ 167,583,453</td></tr></table>

(1) The SEC Pricing Proved Reserves table above values oil and gas reserve quantities and related discounted future net cash flows as of December 31, 2009 assuming a constant realized price of $53.00 per barrel of crude oil and a constant realized price of $3.93 per 1,000 cubic feet (Mcf) of natural gas.

The Sensitivity Case Proved Reserves table above values oil and gas reserve quantities and related discounted future net cash flows as of December 31, 2009 assuming a constant realized price of $71.82 per barrel of crude oil and a constant realized price of $5.07 per 1,000 cubic feet (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. These sensitivity prices were selected because they are consistent with the prior SEC methodology utilizing year-end pricing. 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.

The values presented in both tables above were calculated by Ryder Scott.

(2) Barrels of oil equivalent (“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 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 oil and 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 oil and natural gas reserves.

(4) “PDP” consists of our proved developed producing reserves.

(5) “PDNP” consists of our proved developed nonproducing reserves, awaiting completion.

(6) “PUD” consists of our proved undeveloped reserves present valued net of development cost.






Our December 31, 2009 reserve report includes an assessment of proven undeveloped locations, which includes approximately 93% of our undeveloped acreage. Our current North Dakota and Montana acreage position will allow us to drill approximately 162 net wells based on 640-acre spacing units with production from a single prospect. With 320-acre spacing units we have the ability to drill a total of approximately 578 net wells, including 255 net wells targeting the Bakken formation, 255 net wells targeting the Three Forks formation and 68 net wells targeting the Red River formation.

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.

<table><tr><td colspan="2">SEC Pricing Proved Reserves</td></tr><tr><td colspan="2">Standardized Measure Reconciliation</td></tr><tr><td>Pre-tax Present Value of estimated future net revenues (Pre-tax PV10%)</td><td>$ 87,812,492</td></tr><tr><td>Future income taxes, discounted at 10%</td><td>(20,005,931)</td></tr><tr><td>Standardized measure of discounted future net cash flows</td><td>$ 67,806,561</td></tr></table>

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.

<table><tr><td colspan="2">Sensitivity Case Proved Reserves</td></tr><tr><td colspan="2">Standardized Measure Reconciliation</td></tr><tr><td>Pre-tax Present Value of estimated future net revenues (Pre-tax PV10%)</td><td>$ 167,583,453</td></tr><tr><td>Future income taxes, discounted at 10%</td><td>(50,995,503)</td></tr><tr><td>Standardized measure of discounted future net cash flows</td><td>$ 116,587,950</td></tr></table>

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

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 2009, we continued to focus our operations on acquiring leaseholds and drilling exploratory and developmental wells in the Rocky Mountain Region of the United States, specifically the Williston Basin. We acquired an aggregate of 20,316 additional net mineral acres during 2009, primarily in Mountrail and Dunn Counties of North Dakota but also in Burke, Divide, McKenzie, Williams and other counties of North Dakota. As of December 31, 2009, we had participated in the completion of 179 gross wells with a 100% success rate in the Bakken and Three Forks formations. As of December 31, 2009, our principal assets included approximately 104,000 net acres located in the Williston Basin region of the northern United States and approximately 10,000 net acres located in Yates County, New York, as more fully described under the heading “Properties – Leasehold Properties” in Item 2 of this report.

During 2009, we continued to acquire interests in oil, gas and mineral leases with the intention of increasing our acreage positions in desired prospects. A complete discussion of our significant acquisitions during the past fiscal year is included under the heading "Properties – Recent Acreage Acquisitions" in Item 2 of this report.

## Production Methods

We primarily engage in oil and 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 oil, 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 2009, 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 oil and 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 oil and natural gas produced from wells in which we have an interest. Our operating partners coordinate the transportation of our 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 oil and is readily accepted into the pipeline infrastructure. The weighted average differential reported to us by our producers during the second half of 2009 was $8.57 per barrel below New York Mercantile Exchange (NYMEX) pricing. This differential represents the imbedded transportation costs in moving the oil from wellhead to refinery.

## Competition

The oil and natural gas industry is intensely competitive, and we compete with numerous other oil and gas exploration and production companies. Some of these companies have substantially greater resources than we have. Not only do they explore for and produce 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 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 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 oil and natural gas that we will produce depends on factors beyond our control, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of natural gas pipelines and other transportation facilities, demand for oil and natural gas, the marketing of competitive fuels and the effects of state and federal regulation. The oil and gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.

Our oil production is expected to be sold at prices tied to the spot 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 oil and 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 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 oil and natural gas exploration and production industry as whole.

## Regulation of Oil and Natural Gas Production

Our oil and natural gas exploration, production and related operations, when developed, are subject to extensive rules and regulations promulgated by federal, state, tribal and local authorities and agencies. For example, North Dakota and Montana require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of oil and natural gas. Such states may also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, and the regulation of spacing, plugging and abandonment of such wells. Failure to comply with any such rules and regulations can result in substantial penalties. The regulatory burden on the oil and 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 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 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 oil and natural gas exploration and production. Many states and the federal government have enacted legislation directed at controlling greenhouse gas emissions, and future legislation and regulation could impose additional restrictions or requirements in connection with our drilling and production activities and favor use of alternative energy sources, which could increase operating costs and demand for oil products. As such, our business could be materially adversely affected by domestic and international legislation targeted at controlling climate change.

## Employees

We currently have eight full time employees. Our Chief Executive Officer—Michael Reger—and our Chief Financial Officer—Ryan Gilbertson—are responsible for all material policy-making decisions. They are assisted in the implementation of our company’s business by our Vice President of Operations and our 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, assuming our currently-projected drilling plan. We are using and will continue to use the services of independent consultants and contractors to perform various professional services, particularly in the area of land services and reservoir engineering. We believe that this use of third-party service providers enhances our ability to contain general and administrative expenses.

## Office Locations

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

## Financial Information about Segments and Geographic Areas

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

## Available Information – Reports to Security Holders

Our website address is www.northernoil.com. We make available on this Website under “Investor Relations,” free of charge, our annual reports on Form 10-K (formerly Form 10-KSB), quarterly reports on Form 10-Q (formerly Form 10-QSB), current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC. These filings are also available to the public at the SEC’s Public Reference Room at 100 F Street, NE, Room 1580, Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Electronic filings with the SEC are also available on the SEC internet website at www.sec.gov.

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



## Item 1A. Risk Factors

## Risks Related to our Business

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

The credit crisis and related turmoil in the global financial system may adversely impact our business and our financial condition, and we may face challenges if conditions in the financial markets do not improve. Our ability to access the capital markets may be restricted at a time when we would like, or need, to raise financing, which could have a material negative impact on our flexibility to react to changing economic and business conditions. The economic situation could have a material negative impact on operators upon whom we are dependent for drilling our wells, our lenders or customers, causing them to fail to meet their obligations to us. Additionally, market conditions could have a material negative impact on our crude oil hedging arrangements if our counterparties are unable to perform their obligations or seek bankruptcy protection. We believe we have sufficient capital to fund our 2010 drilling program. However, additional capital would be required in the event that we accelerate our drilling program or that crude oil prices decline substantially resulting in significantly lower revenues.

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

We expect that our cash position, unused credit facility and revenues from oil and gas sales will be sufficient to fund our 2010 drilling program. However, those funds may not be sufficient to fund both our continuing operations and our planned growth. We may require additional capital to continue to grow our business via acquisitions beyond the initial phase of our current properties and to further expand our exploration and development programs. We may be unable to obtain additional capital if and when required.

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

We may pursue sources of additional capital through various financing transactions or arrangements, including joint venturing of projects, debt financing, equity financing or other means. We may not be successful in identifying suitable financing transactions in the time period required or at all, and we may not obtain the capital we require by other means. If we do not succeed in raising additional capital, our resources may not be sufficient to fund our planned expansion of operations following 2010.

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

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



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

We have a limited operating history, and may not be successful in developing profitable business operations.

We have a limited operating history. Our business operations must be considered in light of the risks, expenses and difficulties frequently encountered in establishing a business in the oil and natural gas industries. We first generated revenues from operations in the fiscal year ended December 31, 2008, and have been primarily focused on exploratory drilling and fund raising activities. There is nothing at this time on which to base an assumption that our business operations will prove to be successful in the long-term. Our future operating results will depend on many factors, including:

• our ability to raise adequate working capital;

• success of our development and exploration;

• demand for natural gas and oil;

• the level of our competition;

• our ability to attract and maintain key management and employees; and

• our ability to efficiently explore, develop and produce sufficient quantities of marketable natural gas or oil in a highly competitive and speculative environment while maintaining quality and controlling costs.

To achieve profitable operations in the future, we must, alone or with others, successfully manage the factors stated above, as well as continue to develop ways to enhance our production efforts, when commenced. Despite our best efforts, we may not be successful in our exploration or development efforts, or obtain required regulatory approvals. There is a possibility that some, or all, of our wells may never produce natural gas or oil.

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

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

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

Our business focus is on the oil and gas industry in a limited number of properties, initially in Montana and North Dakota. Larger companies have the ability to manage their risk by diversification. However, we will lack diversification, in terms of both the nature and geographic scope of our business. As a result, we will likely be impacted more acutely by factors affecting our industry or the regions in which we operate than we would if our business were more diversified, enhancing our risk profile. If we do not diversify our operations, our financial condition and results of operations could deteriorate.



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

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

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

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

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

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

The oil and gas industry is highly competitive. Other oil and gas companies may seek to acquire oil and gas leases and other properties and services we will need to operate our business in the areas in which we expect to operate. This competition is increasingly intense as prices of oil and natural gas on the commodities markets have risen in recent years. Additionally, other companies engaged in our line of business may compete with us from time to time in obtaining capital from investors. Competitors include larger companies which, in particular, may have access to greater resources, may be more successful in the recruitment and retention of qualified employees and may conduct their own refining and petroleum marketing operations, which may give them a competitive advantage. In addition, actual or potential competitors may be strengthened through the acquisition of additional assets and interests. If we are unable to compete effectively or respond adequately to competitive pressures, our results of operation and financial condition may be materially adversely affected.

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

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



• meet our capital needs;

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

• allocate our human resources optimally;

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

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

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

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

We generally expect to enter into swap arrangements from time-to-time to hedge our expected production depending on reserves and market conditions. While intended to reduce the effects of volatile oil and natural gas prices, such transactions may limit our potential gains and increase our potential losses if oil and natural gas prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose us to the risk of loss in certain circumstances, including instances in which:

• our production is less than expected;

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

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

## Risks Related To Our Industry

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

The oil and gas markets are very volatile, and we cannot predict future oil and natural gas prices. The price we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. The prices we receive for our production and the levels of our production depend on numerous factors beyond our control. These factors include, but are not limited to, the following:

• changes in global supply and demand for oil and gas;

• the actions of the Organization of Petroleum Exporting Countries;

• the price and quantity of imports of foreign oil and gas;

• political and economic conditions, including embargoes, in oil-producing countries or affecting other oil-producing activity;

• the level of global oil and gas exploration and production activity;

• the level of global oil and gas inventories;

• weather conditions;

• technological advances affecting energy consumption;



• domestic and foreign governmental regulations;

• proximity and capacity of oil and gas pipelines and other transportation facilities;

• the price and availability of competitors’ supplies of oil and gas in captive market areas; and

• the price and availability of alternative fuels.

Furthermore, the recent worldwide financial and credit crisis has generally reduced the availability of liquidity and credit to fund the continuation and expansion of industrial business operations worldwide. The shortage of liquidity and credit combined with recent substantial losses in worldwide equity markets has led to a worldwide economic recession. The slowdown in economic activity caused by such recession has reduced worldwide demand for energy and resulted in somewhat lower oil and natural gas prices.

Lower oil and natural gas prices may not only decrease our revenues on a per unit basis but also may reduce the amount of oil and natural gas that we can produce economically and therefore potentially lower our reserve bookings. A substantial or extended decline in oil or natural gas prices may result in impairments of our proved oil and gas properties and may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures. To the extent commodity prices received from production are insufficient to fund planned capital expenditures, we will be required to reduce spending or borrow to cover any such shortfall. Lower oil and natural gas prices may also reduce the amount of our borrowing base under our credit agreement, which is determined at the discretion of the lenders based on the collateral value of our proved reserves that have been mortgaged to the lenders, and is subject to regular redeterminations, as well as special redeterminations described in the credit agreement.

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

Our future success will depend on the success of our development, exploitation, production and exploration activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Our cost of drilling, completing and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, many factors may curtail, delay or cancel drilling, including the following:

• delays imposed by or resulting from compliance with regulatory requirements;

• pressure or irregularities in geological formations;

• shortages of or delays in obtaining qualified personnel or equipment, including drilling rigs and CO \( _{2} \) ;

• equipment failures or accidents; and

• adverse weather conditions, such as freezing temperatures, hurricanes and storms.

The presence of one or a combination of these factors at our properties could adversely affect our business, financial condition or results of operations.

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

Our future success will depend on the success of our exploratory drilling program. Oil and gas exploration involves a high degree of risk. These risks are more acute in the early stages of exploration. Our ability to produce revenue and our resulting financial performance are significantly affected by the prices we receive for oil and natural gas produced from wells on our acreage. Especially in recent years, the prices at which oil and natural gas trade in



the open market have experienced significant volatility and will likely continue to fluctuate in the foreseeable future due to a variety of influences including, but not limited to, the following:

• domestic and foreign demand for oil and natural gas by both refineries and end users;

• the introduction of alternative forms of fuel to replace or compete with oil and natural gas;

• domestic and foreign reserves and supply of oil and natural gas;

• competitive measures implemented by our competitors and domestic and foreign governmental bodies;

• political climates in nations that traditionally produce and export significant quantities of oil and natural gas (including military and other conflicts in the Middle East and surrounding geographic region) and regulations and tariffs imposed by exporting and importing nations;

• weather conditions; and

• domestic and foreign economic volatility and stability.

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

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

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

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

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



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

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

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

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

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

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

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



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

In order to sell the oil and natural gas that we are able to produce, the operators of our wells may have to make arrangements for storage and distribution to the market. We will rely on local infrastructure and the availability of transportation for storage and shipment of our products, but infrastructure development and storage and transportation facilities may be insufficient for our needs at commercially acceptable terms in the localities in which we operate. This situation could be particularly problematic to the extent that our operations are conducted in remote areas that are difficult to access, such as areas that are distant from shipping and/or pipeline facilities. These factors may affect our ability to explore and develop properties and to store and transport our oil and natural gas production and may increase our expenses.

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

## Environmental risks may adversely affect our business.

All phases of the oil and gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, state and municipal laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances produced in association with oil and gas operations. The legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Compliance with such legislation can require significant expenditures, and a breach may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner we expect may result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require us to incur costs to remedy such discharge. The application of environmental laws to our business may cause us to curtail our production or increase the costs of our production, development or exploration activities.

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

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

## Challenges to our properties may impact our financial condition.

Title to oil and gas interests is often not capable of conclusive determination without incurring substantial expense. While we intend to make appropriate inquiries into the title of properties and other development rights we acquire, title defects may exist. In addition, we may be unable to obtain adequate insurance for title defects, on a commercially reasonable basis or at all. If title defects do exist, it is possible that we may lose all or a portion of our right, title and interests in and to the properties to which the title defects relate. If our property rights are reduced, our ability to conduct our exploration, development and production activities may be impaired. To mitigate title problems, common industry practice is to obtain a Title Opinion from a qualified oil and gas attorney prior to the drilling operations of a well.

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

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



## Risks Related to our Common Stock

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

The market price of our common stock is likely to continue to be highly volatile and could be subject to wide fluctuations in response to a number of factors, some of which are beyond our control, including:

• dilution caused by our issuance of additional shares of common stock and other forms of equity securities, which we expect to make in connection with future capital financings to fund our operations and growth, to attract and retain valuable personnel and in connection with future strategic partnerships with other companies;

• announcements of new acquisitions, reserve discoveries or other business initiatives by our competitors;

• our ability to take advantage of new acquisitions, reserve discoveries or other business initiatives;

• fluctuations in revenue from our oil and gas business as new reserves come to market;

• changes in the market for oil and natural gas commodities and/or in the capital markets generally;

• changes in the demand for oil and natural gas, including changes resulting from the introduction or expansion of alternative fuels;

• quarterly variations in our revenues and operating expenses;

• changes in the valuation of similarly situated companies, both in our industry and in other industries;

• changes in analysts’ estimates affecting our company, our competitors and/or our industry;

• changes in the accounting methods used in or otherwise affecting our industry;

• additions and departures of key personnel;

• announcements of technological innovations or new products available to the oil and gas industry;

• announcements by relevant governments pertaining to incentives for alternative energy development programs;

• fluctuations in interest rates and the availability of capital in the capital markets; and

• significant sales of our common stock, including sales by selling stockholders following the registration of shares under a prospectus.

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



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

Our operating results will likely vary in the future primarily as the result of fluctuations in our revenues and operating expenses, including the coming to market of oil and natural gas reserves that we are able to discover and

develop, expenses that we incur, the prices of oil and natural gas in the commodities markets and other factors. If our results of operations do not meet the expectations of current or potential investors, the price of our common stock may decline.

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

As of December 31, 2009, we had authorized the issuance of up to 2,000,000 shares of common stock underlying options that may be granted, of which options for 1,660,000 shares of common stock had already been granted, and of those granted, 300,000 remain outstanding, pursuant to our 2006 Incentive Stock Option Plan. On January 30, 2009, our Board of Directors also adopted the 2009 Equity Incentive Plan, pursuant to which we 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, 2009, we had issued 642,916 shares of common stock pursuant to our 2009 Equity Incentive Plan. No options have been issued under our 2009 Equity Incentive Plan. If the holders of outstanding options exercise those options or our Compensation Committee determines to grant additional restricted stock awards under our incentive plan, stockholders may experience dilution in the net tangible book value of our common stock. Further, the sale or availability for sale of the underlying shares in the marketplace could depress our stock price.

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

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

## Item 1B. Unresolved Staff Comments

None.

## Item 2. Properties

## Leasehold Properties

As of December 31, 2009, our principal assets included approximately 104,000 net acres located in the Williston Basin region of the northern United States and approximately 10,000 net acres located in Yates County, New York, more fully described as follows:

• Approximately 30,400 net acres located in Mountrail County, North Dakota, within and surrounding to the north south and west of the Parshall Field currently being developed by EOG Resources. Slawson Exploration Company, Inc. (“Slawson”) and others to target the Bakken Shale;

• Approximately 26,800 net acres located in Dunn County, North Dakota, in which we are targeting the Bakken Shale and Three Forks/Sanish formations;

• Approximately 10,000 net acres located in Burke and Divide Counties, North Dakota, targeting the Bakken Shale and Three Forks/Sanish formations near significant drilling activities by Continental Resources;

• Approximately 8,900 net acres located in McKenzie, Williams and Mercer Counties, North Dakota, in which we are targeting the Bakken Shale;

• Approximately 22,400 net acres located in Sheridan County, Montana, representing a stacked pay prospect over which we have significant proprietary 3-D seismic data;

• Approximately 5,500 net acres located in Roosevelt and Richland Counties, Montana, in which we are targeting the Bakken Shale; and

• Approximately 10,000 net acres located in the "Finger Lakes" region of Yates County, New York, in which we are targeting natural gas production from the Trenton/Black River, Marcellus and Queenstown-Medina formations.



We believe the Bakken formation represents one of the most oil rich, rapidly developing and exciting plays in the Continental United States. The North Dakota Geological Survey currently estimates the reserves of the Bakken formation to be approximately 300 billion barrels of oil in place. We commenced drilling on the Bakken properties in late 2007 and increased drilling activities quarter-over-quarter throughout 2008 and 2009.

## Recent Acreage Acquisitions

In 2009, we acquired leasehold interests covering an aggregate of 20,316 net mineral acres in our key prospect areas. The discussion that follows summarizes these acquisitions.

On May 22, 2009, we entered into an agreement with Slawson pursuant to which we acquired certain North Dakota Bakken assets from Windsor Bakken LLC as part of a syndicate led by Slawson. In the transaction we acquired leases covering 3,323 net mineral acres.

On November 3, 2009, we acquired 24 high working interest sections comprising approximately 11,274 net acres located in western McKenzie and Williams Counties of North Dakota. We acquired a 50% participation interest in these properties with Slawson and will participate in drilling on a heads-up basis. These properties are proximal to several recent high-rate producing wells. We expect to begin drilling these properties in early 2011.

On November 13, 2009, we entered into an agreement with Slawson pursuant to which we acquired a 20% participation interest in Slawson’s Big Sky Project in Richland County, Montana. The project area encompasses 11,586 net acres of leases.

On November 17, 2009, we entered into an Exploration and Development Agreement with Area of Mutual Interest with Slawson pursuant to which we acquired a 30% participation interest in Slawson’s Anvil Project in Williams County, North Dakota and Roosevelt County, Montana. The project area encompasses 12,500 net acres of leases.

In addition to acquiring acreage through large block acquisitions, we have organically acquired approximately 5,289 net mineral acres in our key prospect areas.



## Developed and Undeveloped Acreage

The following table summarizes our estimated gross and net developed and undeveloped acreage by county at December 31, 2009. Net acreage represents our percentage ownership of gross acreage. The following table does not include acreage in which our interest is limited to royalty and overriding royalty interests.

<table><tr><td rowspan="2"></td><td colspan="2">Developed Acreage</td><td colspan="2">Undeveloped Acreage</td><td colspan="2">Total Acreage</td></tr><tr><td>Gross</td><td>Net</td><td>Gross</td><td>Net</td><td>Gross</td><td>Net</td></tr><tr><td>North Dakota</td><td>44,076</td><td>7,433</td><td>396,685</td><td>68,084</td><td>440,761</td><td>75,516</td></tr><tr><td>Montana</td><td>1,046</td><td>479</td><td>32,514</td><td>27,459</td><td>33,560</td><td>27,938</td></tr><tr><td>New York</td><td>0</td><td>0</td><td>10,000</td><td>10,000</td><td>10,000</td><td>10,000</td></tr><tr><td></td><td>Total:</td><td>45,122</td><td>7,912</td><td>439,199</td><td>105,542</td><td>484,321</td></tr></table>

## Production History

The following table presents information about our produced oil and gas volumes during each fiscal quarter in 2009 and the year ended December 31, 2009. The table below does not provide any information for our fiscal year ended December 31, 2007 because we did not commence drilling activities until the fourth fiscal quarter of 2007 and did not receive payment or recognize revenue from crude oil or natural gas sales in 2007. As of December 31, 2009, we were selling oil and natural gas from a total of 179 gross wells, all of which are located within the Williston Basin. As of December 31, 2008, we were selling oil and natural gas from a total of 36 gross wells. All data presented below is derived from accrued revenue and production volumes for the relevant period indicated.

<table><tr><td rowspan="2"></td><td colspan="2">Year Ended December 31,</td></tr><tr><td>2009</td><td>2008</td></tr><tr><td>Net Production:</td><td></td><td></td></tr><tr><td>Oil (Bbl)</td><td>274,328</td><td>50,880</td></tr><tr><td>Natural Gas (Mcf)</td><td>47,305</td><td>3,969</td></tr><tr><td>Barrel of Oil Equivalent (Boe)</td><td>282,212</td><td>51,542</td></tr><tr><td>Average Sales Prices:</td><td></td><td></td></tr><tr><td>Oil (per Bbl)</td><td>$ 60.45</td><td>$ 75.63</td></tr><tr><td>Effect of Oil Hedges on Average Price (per Bbl)</td><td>$ (3.60)</td><td>$ 15.31</td></tr><tr><td>Oil Net of Hedging (per Bbl)</td><td>$ 56.85</td><td>$ 90.94</td></tr><tr><td>Natural Gas (per Mcf)</td><td>$ 3.81</td><td>$ 8.19</td></tr><tr><td>Effect of Natural Gas Hedges on Average Price (per Mcf)</td><td>--</td><td>--</td></tr><tr><td>Natural Gas Net of Hedging (per Mcf)</td><td>$ 3.81</td><td>$ 8.19</td></tr><tr><td>Average Production Costs:</td><td></td><td></td></tr><tr><td>Oil (per Bbl)</td><td>$ 2.67</td><td>$ 1.37</td></tr><tr><td>Natural Gas (per Mcf)</td><td>$ 0.19</td><td>$ 0.32</td></tr><tr><td>Barrel of Oil Equivalent (BOE)</td><td>$ 2.63</td><td>$ 1.38</td></tr></table>



## Depletion of oil and natural gas properties

Our depletion expense is driven by many factors including certain exploration costs involved in the development of producing reserves, production levels and estimates of proved reserve quantities and future developmental costs. The following table presents our depletion expenses during 2008 and 2009.

<table><tr><td rowspan="2"></td><td colspan="2">Year Ended December 31,</td></tr><tr><td>2009</td><td>2008 (adjusted)</td></tr><tr><td>Depletion of oil and natural gas properties</td><td>$ 4,250,983</td><td>$ 677,915</td></tr></table>

 \( ^{*} \)  See Note 2 to the financial statements accompanying this report.

## Productive Oil Wells

The following table summarizes gross and net productive oil wells by state at December 31, 2009, 2008 and 2007. A net well represents our percentage ownership of a gross well. No wells have been permitted or drilled on any of our Yates County, New York acreage. The following table does not include wells in which our interest is limited to royalty and overriding royalty interests. The following table also does not include wells which were awaiting completion, in the process of completion or awaiting flowback subsequent to fracture stimulation.

Year Ended December 31,

<table><tr><td rowspan="2"></td><td colspan="2">2009</td><td colspan="2">2008</td><td colspan="2">2007</td></tr><tr><td>Gross</td><td>Net</td><td>Gross</td><td>Net</td><td>Gross</td><td>Net</td></tr><tr><td>North Dakota</td><td>170</td><td>8.17</td><td>34</td><td>1.54</td><td>1</td><td>0.06</td></tr><tr><td>Montana</td><td>9</td><td>1.02</td><td>2</td><td>0.50</td><td>1</td><td>0.10</td></tr><tr><td>Total</td><td>179</td><td>9.19</td><td>36</td><td>2.04</td><td>2</td><td>0.16</td></tr></table>

## Dry Holes

As of December 31, 2009, we have participated in the completion of 179 gross wells with a 100% success rate in the Bakken and Three Forks formations. In the second quarter of 2007, we participated in the Teigen Trust #9-13 with a 6.25% working interest, a well identified, proposed and drilled by Kodiak Oil and Gas, Inc. The well was intended to target the Red River formation, but produced a dry hole. This is the only dry hole in our company’s history.

## Research and Development

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

## Reserves

We completed our most recent reservoir engineering calculation as of December 31, 2009. Tables summarizing the results of our most recent reserve report are included under the heading “Business – Reserves” in Item 1 of this report. A complete discussion of our proved reserves is set forth in “Supplemental Oil and Gas Information” to our financial statements included later in this report.

## Delivery Commitments

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



## Item 3. Legal Proceedings

As of March 8, 2010, our company was a party to one litigation claim arising in the ordinary course of business and seeking the quieting of title for a leasehold interest acquired from a third party. To the knowledge of management, no federal, state or local governmental agency is presently contemplating any proceeding against our company. No director, executive officer or affiliate of our company or owner of record or beneficially of more than five percent of our company’s common stock is a party adverse to our company or has a material interest adverse to our company in any proceeding.

On or about December 19, 2008, we instituted a FINRA dispute resolution matter against UBS Financial Services, Inc. (“UBS”) relating to certain unauthorized trades conducted by UBS in connection with our commodities hedging account at that institution. The matter related to UBS’s improper attribution of an unauthorized long trade to our hedging account. Ultimately UBS liquidated the contracts at a loss without any instruction from our company. The matter was presented to a FINRA arbitration board in September 2009. On November 12, 2009, FINRA issued an Award in favor of our company directing UBS to pay us compensatory damages in the amount of $875,352, the entire loss in dispute, plus interest at the statutory rate of 10% per annum from and including October 13, 2008, through and including October 1, 2009, for a total award of $960,018.

Our management believes that all litigation matters in which we are involved are not likely to have a material adverse effect on our financial position, cash flows or results of operations.

## Item 4. Reserved

## PART II

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

## Market Information

Our common stock was listed on the OTC Bulletin Board of the National Association of Securities Dealers (“NASD”) on January 19, 2006, under the symbol “KNTX”, but there was no active trading prior to approximately December 2006. There was no established public trading market for our common stock prior to April 13, 2007. Effective April 13, 2007, after the Merger and our name change, our trading symbol was changed to “NOGS.OB.” Our common stock commenced trading on the AMEX on March 26, 2008 under the symbol “NOG.”

The high and low sales prices for shares of common stock of our company for each quarter during 2008 and 2009 are set forth below.

<table><tr><td rowspan="2">2009</td><td colspan="2">Sales Price</td></tr><tr><td>High</td><td>Low</td></tr><tr><td>First Quarter</td><td>$ 4.24</td><td>$ 2.01</td></tr><tr><td>Second Quarter</td><td>8.89</td><td>3.40</td></tr><tr><td>Third Quarter</td><td>8.44</td><td>4.74</td></tr><tr><td>Fourth Quarter</td><td>12.66</td><td>7.65</td></tr></table>

<table><tr><td rowspan="2">2008</td><td colspan="2">Sales Price</td></tr><tr><td>High</td><td>Low</td></tr><tr><td>First Quarter</td><td>$ 7.30</td><td>$ 5.65</td></tr><tr><td>Second Quarter</td><td>16.40</td><td>6.95</td></tr><tr><td>Third Quarter</td><td>14.00</td><td>5.14</td></tr><tr><td>Fourth Quarter</td><td>8.13</td><td>2.05</td></tr></table>

The closing price for our common stock on the NYSE Amex Equities Market on March 1, 2010 was $12.60 per share.



## Comparison Chart

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

The following graph compares the 32-month cumulative total shareholder returns since completion of our reverse merger on April 13, 2007 of Northern Oil and Gas, Inc., and the cumulative total returns of Standard & Poor's Composite 500 Index and the Amex Oil Index for the same period. This graph assumes $100 was invested in the stock or the Index on April 13, 2007 and also assumes the reinvestment of dividends. We have not included any graph for any period prior to April 13, 2007, because there was no active trading in our common stock prior to April 13, 2007 and, as such, data is not available for any period prior to such date.



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

<table><tr><td></td><td>4/13/2007</td><td>12/31/2007</td><td>12/31/2008</td><td>12/31/2009</td></tr><tr><td>Northern Oil and Gas, Inc.</td><td>$ 100.00</td><td>$ 173.75</td><td>$ 65.00</td><td>$ 296.00</td></tr><tr><td>Standard &amp; Poor&#x27;s Composite 500 Index</td><td>100.00</td><td>104.82</td><td>66.04</td><td>83.52</td></tr><tr><td>Amex Oil Index</td><td>100.00</td><td>125.65</td><td>92.74</td><td>99.77</td></tr></table>

## Holders

As of March 1, 2010, we had 43,911,044 shares outstanding of our common stock, held by approximately 405 shareholders of record. The number of record holders does not necessarily bear any relationship to the number of beneficial owners of our common stock.



## Dividends

The payment of dividends is subject to the discretion of our Board of Directors and will depend, among other things, upon our earnings, our capital requirements, our financial condition, and other relevant factors. We have not paid or declared any dividends upon our common stock since our inception and, by reason of our present financial status and our contemplated financial requirements and do not anticipate paying any dividends upon our common stock in the foreseeable future. We intend to reinvest any earnings in the development and expansion of our business. Any cash dividends in the future to common stockholders will be payable when, as and if declared by

our Board of Directors or our Compensation Committee, based upon either the Board’s or the Committee’s assessment of:

• our financial condition and performance;

• earnings;

• need for funds;

• capital requirements;

• prior claims of preferred stock to the extent issued and outstanding; and

• other factors, including income tax consequences, restrictions and any applicable laws.

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

## Recent Sales of Unregistered Securities; Use of Proceeds from Registered Securities

On November 16, 2009, we issued 12,533 shares of unregistered common stock to Missouri River Royalty Corporation as partial consideration for our acquisition of leases covering approximately 46 net mineral acres in North Dakota and related pre-paid drilling expenses. These shares were issued pursuant to an agreement originally entered into on October 1, 2008. On December 18, 2009, we issued 66,472 shares of unregistered common stock to certain parties controlling mineral rights as partial consideration for our acquisition of leases covering approximately 1,084 net mineral acres in North Dakota.

The foregoing transactions were approved by our board of directors. None of the foregoing shares of our common stock were issued for cash consideration and, as such, we did not receive any proceed from the issuance of the foregoing securities. All of the foregoing shares were issued pursuant to the exemption from registration provided in Section 4(2) of the Act. In each instance, the recipients of the shares were afforded an opportunity for effective access to files and records of our company that contained the relevant information needed to make its investment decision, including our company's financial statements and reports filed pursuant to the Exchange Act. We reasonably believe that each recipient, immediately prior to issuing the shares, had such knowledge and experience in financial and business matters that it was capable of evaluating the merits and risks of its investment. Each recipient had the opportunity to speak with our officers and directors on several occasions prior to their investment decision.

## Item 6. Selected Financial Data

The financial statement information set forth below is derived from our balance sheets as of December 31, 2009, 2008, and 2007, and the related statements of operations, stockholders' equity, and cash flows for the years ended December 31, 2009, 2008, and 2007 and for the period from inception [October 5, 2006] through December 31, 2006 included elsewhere in this report. Financial statement information for the year ended December 31, 2005 and the balance sheet information at December 31, 2006 and 2005 are derived from audited financial statements presented in our December 31, 2006 Form 10-KSB report and not included in this report, which financial statements were the historical financial statements of Kentex Petroleum, Inc, our company prior to the acquisition of Northern on March 20, 2007.



<table><tr><td></td><td>Year Ended December 31, 2009</td><td>Year Ended December 31, 2008, Adjusted</td><td>Year Ended December 31, 2007</td><td>From Inception on October 5, 2006 through December 31, 2006</td><td>Year Ended December 31, 2005</td></tr><tr><td>Statements of Income Information:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Revenues</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Oil and Gas Sales</td><td>$ 15,171,824</td><td>$ 3,542,994</td><td>--</td><td>--</td><td>--</td></tr><tr><td>Gain (Loss) on Settled Derivatives</td><td>(624,541)</td><td>778,885</td><td>--</td><td>--</td><td>--</td></tr><tr><td>Mark-to-Market of Derivative Instruments</td><td>(363,414)</td><td></td><td></td><td></td><td></td></tr><tr><td>Other Revenue</td><td>37,630</td><td>--</td><td>--</td><td>--</td><td>--</td></tr><tr><td>Total Revenues</td><td>$ 14,221,499</td><td>$ 4,321,879</td><td>--</td><td>--</td><td>--</td></tr><tr><td>Operating Expenses</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Production Expenses</td><td>$ 754,976</td><td>$ 70,954</td><td>--</td><td>--</td><td>--</td></tr><tr><td>Production Taxes</td><td>1,300,373</td><td>203,182</td><td>--</td><td>--</td><td>--</td></tr><tr><td>General and Administrative Expense</td><td>2,452,823</td><td>1,985,914</td><td>$ 1,754,826</td><td>$ 76,374</td><td>$ 12,267</td></tr><tr><td>Share Based Compensation</td><td>1,233,507</td><td>105,375</td><td>2,754,917</td><td>--</td><td>--</td></tr><tr><td>Depletion Oil and Gas Properties</td><td>4,250,983</td><td>677,915</td><td>--</td><td>--</td><td>--</td></tr><tr><td>Depreciation and Amortization</td><td>91,794</td><td>67,060</td><td>3,446</td><td>--</td><td>--</td></tr><tr><td>Accretion of Discount on Asset Retirement Obligations</td><td>8,082</td><td>1,030</td><td>--</td><td>--</td><td>--</td></tr><tr><td>Total Expenses</td><td>$ 10,092,538</td><td>$ 3,111,430</td><td>$ 4,513,189</td><td>$ 76,374</td><td>$ 12,267</td></tr><tr><td>Income (Loss) from Operations</td><td>$ 4,128,961</td><td>$ 1,210,449</td><td>$ (4,513,189)</td><td>$ (76,374)</td><td>$ (12,267)</td></tr><tr><td>Other Income</td><td>135,991</td><td>383,891</td><td>207,896</td><td>267</td><td>25,000-</td></tr><tr><td>Income (Loss) Before Income Taxes</td><td>$ 4,264,952</td><td>$ 1,594,340</td><td>$ (4,305,293)</td><td>$ (76,107)</td><td>$ (12,733)</td></tr><tr><td>Income Tax Provision (Benefit)</td><td>1,466,000</td><td>(830,000)</td><td>--</td><td>--</td><td>--</td></tr><tr><td>Net Income (Loss)</td><td>$ 2,798,952</td><td>$ 2,424,340</td><td>$ (4,305,293)</td><td>$ (76,107)</td><td>$ (12,733)</td></tr><tr><td>Net Income (Loss) Per Common Share - Basic</td><td>0.08</td><td>0.08</td><td>(0.18)</td><td>(0.01)</td><td>(0.01)</td></tr><tr><td>Net Income (Loss) Per Common Share - Diluted</td><td>0.08</td><td>0.07</td><td>(0.18)</td><td>(0.01)</td><td>(0.01)</td></tr><tr><td>Weighted Average Shares Outstanding - Basic</td><td>36,705,267</td><td>31,920,747</td><td>23,667,119</td><td>18,000,000</td><td>2,357,998</td></tr><tr><td>Weighted Average Shares Outstanding - Diluted</td><td>36,877,070</td><td>32,653,552</td><td>23,667,119</td><td>18,000,000</td><td>2,357,998</td></tr><tr><td>Balance Sheet Information:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Total Assets</td><td>$ 135,594,968</td><td>$ 54,520,399</td><td>$ 18,131,464</td><td>$ 1,105,935</td><td>--</td></tr><tr><td>Total Liabilities</td><td>$ 12,035,518</td><td>$ 4,991,336</td><td>$ 224,247</td><td>$ 1,143,067</td><td>$ 30,811</td></tr><tr><td>Stockholder&#x27;s Equity (Deficit)</td><td>$ 123,559,450</td><td>$ 49,529,063</td><td>$ 17,907,217</td><td>$ (37,132)</td><td>$ (30,811)</td></tr><tr><td>Statement of Cashflow Information:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Net cash used provided by (used for) operating activities</td><td>$ 9,812,910</td><td>$ 2,506,492</td><td>$ (491,509)</td><td>$ (38,532)</td><td>--</td></tr><tr><td>Net cash used provided by (used for) investing activities</td><td>$ (71,848,701)</td><td>$ (40,357,962)</td><td>$ (5,078,758)</td><td>$ (255,000)</td><td>--</td></tr><tr><td>Net cash used provided by (used for) financing activities</td><td>$ 67,488,447</td><td>$ 28,519,526</td><td>$ 14,832,992</td><td>$ 1,143,467</td><td>--</td></tr></table>



In the third quarter of 2009, we changed our method of accounting for drilling costs from the accrual of drilling costs at the time drilling commenced for a well to recording the costs when amounts are invoiced by operators. Recording drilling costs when the invoices are received from operators is deemed preferable as it better represents our actual drilling costs. The recording of drilling costs in this method also is consistent with other companies in the oil and gas industry. The change decreased Depletion Expense by $512,794, increased Income Tax Provision by $206,000, and increased Net Income by $306,794 or $0.01 per share on a diluted basis for the nine months ended September 30, 2009. The effect of the change on the three months ended September 30, 2009 was to decrease Depletion Expense by $261,870, increase Income Tax Provision by $105,000 and to Increase Net Income by $156,870 or $0.00 per share on a diluted basis.

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

The following discussion should be read in conjunction with the “Selected Financial Data” in Item 6 and the Financial Statements and Accompanying Notes appearing elsewhere in this report. A discussion of our past financial results before March 20, 2007 is not pertinent to the business plan of our company on a going forward basis, due to the change in our business which occurred upon consummation of the merger on March 20, 2007.

## Overview and Outlook

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

As of March 1, 2010, we controlled the rights to mineral leases covering approximately 119,720 net acres of land. Our goal is to continue to explore for and develop hydrocarbons within the mineral leases we control as well as continue to expand our acreage position should opportunities present themselves. In order to accomplish our objectives we will need to achieve the following;

• Continue to develop our substantial inventory of high quality core Bakken acreage with results consistent with those to-date;

• Retain and attract talented personnel;

• Continue to be a low-cost producer of hydrocarbons; and

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



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

<table><tr><td rowspan="2"></td><td colspan="3">Year End December 31,</td></tr><tr><td>2009</td><td>2008 Adjusted</td><td>2007</td></tr><tr><td>Net Production:</td><td></td><td></td><td></td></tr><tr><td>Oil (Bbl)</td><td>274,328</td><td>50,880</td><td>-</td></tr><tr><td>Natural Gas (Mcf)</td><td>47,305</td><td>3,969</td><td>-</td></tr><tr><td>Net Sales:</td><td></td><td></td><td></td></tr><tr><td>Oil Sales</td><td>$ 14,977,556</td><td>$ 3,510,596</td><td>-</td></tr><tr><td>Natural Gas</td><td>194,268</td><td>32,397</td><td>-</td></tr><tr><td>Gain (Loss) on Settled Derivatives</td><td>(624,541)</td><td>778,885</td><td>-</td></tr><tr><td>Mark-to-Market on Derivative Instruments</td><td>(363,414)</td><td>-</td><td>-</td></tr><tr><td>Other Revenues</td><td>37,630</td><td>-</td><td>-</td></tr><tr><td>Total Revenues</td><td>$ 14,221,499</td><td>$ 4,321,879</td><td>-</td></tr><tr><td>Average Sales Prices:</td><td></td><td></td><td></td></tr><tr><td>Oil (per Bbl)</td><td>$ 60.45</td><td>$ 75.63</td><td>-</td></tr><tr><td>Effect of Oil Hedges on Average Price (per Bbl)</td><td>$ (3.60)</td><td>$ 15.31</td><td>-</td></tr><tr><td>Oil Net of Hedging (per Bbl)</td><td>$ 56.85</td><td>$ 90.94</td><td>-</td></tr><tr><td>Natural Gas (per Mcf)</td><td>$ 3.81</td><td>$ 8.19</td><td>-</td></tr><tr><td>Effect of Natural Gas Hedges on Average Price (per Mcf)</td><td>-</td><td>-</td><td>-</td></tr><tr><td>Natural gas net of hedging (per Mcf)</td><td>$ 3.81</td><td>$ 8.19</td><td>-</td></tr><tr><td>Operating Expenses:</td><td></td><td></td><td></td></tr><tr><td>Production Expenses</td><td>$ 754,976</td><td>$ 70,954</td><td>-</td></tr><tr><td>Production Taxes</td><td>$ 1,300,373</td><td>$ 203,182</td><td>-</td></tr><tr><td>General and Administrative Expense (Including Share Based Compensation)</td><td>$ 3,686,330</td><td>$ 2,091,289</td><td>$ 4,509,743</td></tr><tr><td>Depletion of Oil and Gas Properties*</td><td>$ 4,250,983</td><td>$ 677,915</td><td>-</td></tr></table>

 \( ^{*} \)  See Note 2 to the financial statements accompanying this report.

## Results of Operations for the periods ended December 31, 2008 and December 31, 2009.

During 2008 and 2009 we significantly increased our drilling activities, generated income and achieved net earnings for both the 2008 and 2009 fiscal years. To-date, we have developed approximately seven percent of our total drillable acreage inventory (assuming one well per 640-acre spacing unit) and we expect to continue to add substantial volumes of production on a quarter-over-quarter basis going forward into the foreseeable future.

As of December 31, 2009, we had established production from 179 gross (9.19 net) wells in which we hold working interests, 36 gross (2.04 net) wells of which had established production as of December 31, 2008. Our production at December 31, 2009 approximated 1,508 barrels of oil per day, compared to approximately 460 barrels of oil per day as of December 31, 2008. Our production increased to 1,986 barrels of oil per day as of March 1, 2010.

We drilled with a 100% success rate in 2008 and 2009 with 176 Bakken or Three Forks wells completed or completing. We also had three successful Red River discoveries at December 31, 2009. As of March 1, 2010, we expect to participate in the drilling of approximately 200 gross (15 net) wells in 2010.

Our revenues, costs and net income increased in 2009 compared to 2008 as we continued our development plans and significantly increased our production. Revenues for the twelve-month period ended December 31, 2009 were $14,221,499, compared to $4,321,879 for the twelve-month period ended December 31, 2008 primarily due to increases in production.



Adjusted total cash and non-cash expenses (including production expenses, production taxes, general and administrative expenses, director fees, depletion expenses, depreciation and amortization expenses) for the twelve month period ended December 31, 2009 were $10,092,538 and for the twelve-month period ended December 31, 2008 were $3,111,430. Of this amount in 2009, approximately $1,233,507 consisted of non-cash expense related to the issuance of restricted stock and an additional $4,250,983 consisted of non-cash depletion expenses. Depletion expenses for the twelve-month period ended December 31, 2008 were $677,915.

We had net income of $2,798,952 (representing approximately $0.08 per basic share) for the twelve-month period ended December 31, 2009 compared to adjusted net income of $2,424,340 (representing approximately $0.08 per basic share) for the twelve-month period ended December 31, 2008.

## Results of Operations for the periods ended December 31, 2007 and December 31, 2008.

Our first successful well commenced drilling in the fourth quarter of 2007, and we did not realize revenue from that well until the first quarter of 2008. During 2008 we significantly increased our drilling activities compared to 2007, generated income and achieved net earnings in the third and fourth quarters of 2008 and for the 2008 fiscal year as a whole. Our production at December 31, 2008 approximated 460 barrels of oil per day. This compares to approximately 100 barrels of oil per day as of December 31, 2007.

Revenues for the twelve-month period ended December 31, 2008 were $4,321,879, compared to no revenues for the twelve-month period ended December 31, 2007. Our expenses in fiscal years 2006 and 2007 consisted principally of general and administrative costs. Our costs increased moderately as we proceeded with our development plans in 2008. Total expenses for the twelve-month period ended December 31, 2008 were $3,111,430 and for the twelve-month period ended December 31, 2007 were $4,513,189. We had net income of $2,424,340 (representing approximately $0.08 per basic share) for the twelve-month period ended December 31, 2008, compared to a net loss of $4,305,293 for the twelve-month period ended December 31, 2007.

## Operation Plan

We expect to drill approximately 15 net wells in 2010 with drilling capital expenditures approximating $67.5 million. The 2010 wells are expected to target both the Bakken and Three Forks formations. Drilling capital expenditures are expected to increase in 2010 compared to previously published guidance due to the continued success of longer laterals and additional fractional stimulation stages. We currently expect to drill wells during 2010 at an average completed cost of $4.5 million per well. Based on evolving conditions in the field, we expect to deploy approximately $10 million towards further strategic acreage acquisitions during 2010. We expect to fund all 2010 commitments using cash-on-hand, cash flow and our currently undrawn credit facility.

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

## Liquidity and Capital Resources

Liquidity is a measure of a company’s ability to meet potential cash requirements. We have historically met our capital requirements through the issuance of common stock and by short term borrowings. In the future, we anticipate we will be able to provide the necessary liquidity by the revenues generated from the sales of our oil and gas reserves in our existing properties, however, if we do not generate sufficient sales revenues we will continue to finance our operations through equity and/or debt financings.

The following table summarizes total current assets, total current liabilities and working capital at December 31, 2009.

<table><tr><td>Assets</td><td>$ 42,017,813</td><td>Current</td></tr><tr><td>Liabilities</td><td>$ 8,910,256</td><td>Current</td></tr><tr><td>Capital</td><td>$ 33,107,557</td><td>Working</td></tr></table>



On February 27, 2009, we completed the closing of a revolving credit facility with CIT that provides up to a maximum principal amount of $25 million of working capital for exploration and production operations (the "Credit Facility"). The borrowing base of funds available under the Credit Facility will be redetermined semi-annually based upon the net present value, discounted at 10% per annum, of the future net revenues expected to accrue from our interests in proved reserves estimated to be produced from our oil and gas properties. $16 million of financing is currently available under the Credit Facility. An additional $9 million of financing could become available upon subsequent borrowing base redeterminations based on the deployment of funds from the Credit Facility. The Credit Facility terminates on February 27, 2012. As of December 31, 2009, we had no borrowings outstanding under the Credit Facility.

We have 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 be outstanding for a period of one, three or six months (as designated by us) and bear interest at a rate equal to 5.50% over the one-month, three-month or six-month LIBOR rate to be no less than 2.50%. Any borrowings not designated as being based upon LIBOR will have no specified term and generally will bear interest at a rate equal to 4.50% over the greater of (a) the current three-month LIBOR rate plus 1.0% or (b) the current prime rate as published by JP Morgan Chase Bank, N.A. We have 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 loan 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 Credit Agreement in connection with the Credit Facility, failure to observe or perform certain covenants, conditions or agreements under the Credit Facility, a change in control of our company, default under any other material indebtedness we might have, bankruptcy and similar proceedings and failure to pay disbursements from lines of credit issued under the Credit Facility.

The Credit Facility requires that we enter into a swap agreement with Macquarie Bank Limited (“Macquarie”) to hedge production over the 36-month term of the Credit Facility. We have strategically entered into constant priced swap arrangements with Macquarie since inception of the Credit Facility to hedge our expected production. A full discussion of our current swap arrangements is set forth in “Quantitative and Qualitative Disclosures about Market Risk – Commodity Price Risk” in Item 7A of this report.

All of our obligations under the Credit Facility and the swap agreements with Macquarie are secured by a first priority security interest in any and all of our assets pursuant to the terms of a Guaranty and Collateral Agreement and perfected by a mortgage, notice of pledge and security and similar documents.



## Follow-On Equity Offerings

On June 30, 2009, we completed a follow-on equity offering pursuant to which we sold 2.25 million shares of common stock to various institutional investors for $6.00 per share, resulting in gross proceeds of $13.5 million. Net proceeds to our company following deduction of agency fees and expenses were approximately $12.7 million and were used to repay outstanding borrowings under our Credit Facility, primarily including borrowings incurred in connection with our acquisition of North Dakota Bakken assets from Windsor Bakken LLC. C.K. Cooper & Company acted as lead placement agent for the offering.

On November 4, 2009, we completed an additional follow-on equity offering pursuant to which we sold 6.5 million shares of common stock to various institutional investors for $9.12 per share, resulting in gross proceeds of $59.3 million. Net proceeds to our company following deduction of agency fees and expenses were approximately $56.3 and were used to repay outstanding borrowings under our Credit Facility, pursue acquisition opportunities and for other working capital purposes. Canaccord Adams Inc. acted as lead placement agent for the offering. FIG Partners, LLC acted as co-placement agent for the offering.

## Satisfaction of Our Cash Obligations for the Next 12 Months

With the addition of equity capital during 2009 and our Credit Facility, we believe we have sufficient capital to meet our drilling commitments and expected general and administrative expenses for the next twelve months at a minimum. Nonetheless, any strategic acquisition of assets may require us to access the capital markets at some point in 2010. We may also choose to access the equity capital markets rather than our Credit Facility or other debt instruments to fund accelerated or continued drilling at the discretion of management and depending on prevailing market conditions. We will evaluate any potential opportunities for acquisitions as they arise. Given our non-leveraged asset base and anticipated growing cash flows, we believe we are in a position to take advantage of any appropriately priced sales that may occur. However, there can be no assurance that any additional capital will be available to us on favorable terms or at all.

Over the next 24 months it is possible that our existing capital, the Credit Facility and anticipated funds from operations may not be sufficient to sustain continued acreage acquisition. Consequently, we may seek additional capital in the future to fund growth and expansion through additional equity or debt financing or credit facilities. No assurance can be made that such financing would be available, and if available it may take either the form of debt or equity. In either case, the financing could have a negative impact on our financial condition and our stockholders.

Though we achieved profitability in 2008 and remained profitable throughout 2009, our prospects must be considered in light of the risks, expenses and difficulties frequently encountered by companies in their early stage of operations, particularly companies in the oil and gas exploration industry. Such risks include, but are not limited to, an evolving and unpredictable business model and the management of growth. To address these risks we must, among other things, implement and successfully execute our business and marketing strategy, continue to develop and upgrade technology and products, respond to competitive developments, and attract, retain and motivate qualified personnel. There can be no assurance that we will be successful in addressing such risks, and the failure to do so can have a material adverse effect on our business prospects, financial condition and results of operations.

## Effects of Inflation and Pricing

The oil and gas industry is very cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry put extreme pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do all associated costs. Conversely, in a period of declining prices, associated cost declines are likely to lag and may not adjust downward in proportion. Material changes in prices also impact our current revenue stream, estimates of future reserves, borrowing base calculations of bank loans, impairment assessments of oil and gas properties, and values of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and gas companies and their ability to raise capital, borrow money and retain personnel. While we do not currently expect business costs to materially increase, higher prices for oil and natural gas could result in increases in the costs of materials, services and personnel.



## Contractual Obligations and Commitments

As of December 31, 2009, we did not have any material long-term debt obligations, capital lease obligations, operating lease obligations or purchase obligations requiring future payments other than our office lease that expires on January 31, 2013, and outstanding promissory notes issued to our executive officers. The following table illustrates our contractual obligations as of December 31, 2009.

Payment due by Period

<table><tr><td rowspan="2">Contractual Obligations</td><td colspan="6">Less than 1</td><td rowspan="2">More than 5 years</td></tr><tr><td>Total</td><td colspan="3">year</td><td>1-3 years</td><td>3-5 years</td></tr><tr><td>Office Lease (1)</td><td>$ 462,474</td><td>$ 148,151</td><td>$</td><td>314,323</td><td>$</td><td>--</td><td>$ --</td></tr><tr><td>Note Payable to Michael L. Reger (2)</td><td>$ 250,000</td><td>$ --</td><td>$ 250,000</td><td>$ --</td><td>$ --</td><td>$ --</td><td>--</td></tr><tr><td>Note Payable to Ryan R. Gilbertson (2)</td><td>$ 250,000</td><td>$ --</td><td>$ 250,000</td><td>$ --</td><td>$ --</td><td>$ --</td><td>--</td></tr><tr><td>Automobile Leases (3)</td><td>$ 61,116</td><td>$ 41,372</td><td>$ 19,744</td><td>$ --</td><td>$ --</td><td>$ --</td><td>--</td></tr><tr><td></td><td>$ 1,023,590</td><td>$ 189,523</td><td>$ 834,067</td><td>$ --</td><td>$ --</td><td>$ --</td><td>--</td></tr></table>

(1) Our office lease commenced on February 1, 2008 and continues for a period of five years.

(2) In February 2009, our Audit Committee and the Compensation Committee approved the issuance of $250,000 principal amount non-negotiable, unsecured subordinated promissory notes to both Michael Reger – our Chief Executive Officer – and Ryan Gilbertson – our Chief Financial Officer – in lieu of paying cash bonuses earned in 2008. The notes bear interest at a rate of 12% per annum and are subordinate to any secured debt of our company. Our Credit Facility now limits our ability to make interest and principal payments on the notes. All unpaid principal and interest on the notes are due and payable in full in a single lump sum on March 8, 2013.

(3) In July 2007, we entered into automobile leases for vehicles utilized by two of our employees, which expire in July, 2010. In September 2008 we entered into automobile leases for vehicles utilized by two additional employees, which expire in September, 2011.

## Product Research and Development

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

## Expected Purchase or Sale of Any Significant Equipment

We do not anticipate the purchase or sale of any plant or significant equipment as such items are not required by us at this time or anticipated to be needed in the next twelve months.

## Critical Accounting Policies

Note 2 to the Financial Statements and Accompanying Notes appearing elsewhere in this report describe various accounting policies critical to an understanding of our financial condition.



We currently do not have any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.

## Item 7A. Quantitative and Qualitative Disclosures about Market Risk

## Commodity Price Risk

The price we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. Crude oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and gas have been volatile, and these markets will likely continue to be volatile in the future. The prices we receive for our production depend on numerous factors beyond our control. Our revenue during 2009 generally would have increased or decreased along with any increases or decreases in crude oil or natural gas prices, but the exact impact on our income is indeterminable given the variety of expenses associated with producing and selling oil that also increase and decrease along with oil prices.

We have previously entered into derivative contracts to achieve a more predictable cash flow by reducing our exposure to oil and natural gas price volatility. On November 1, 2009, due to the volatility of price differentials in the Williston Basin, we de-designated all derivatives that were previously classified as cash flow hedges and in addition, we have elected not to designate any subsequent derivative contracts as accounting hedges. 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 and unrealized gains or losses are recorded as gain (loss) on derivatives net, as an increase or decrease in revenues on the Statement of Operations rather than as a component of other comprehensive income (loss) or other Income (expense). We had the following swap arrangements outstanding as of December 31, 2009:

<table><tr><td rowspan="2">Dates</td><td colspan="2">Volumes (bbl/month)</td><td rowspan="2">Price</td></tr><tr><td>3,000</td><td>$</td></tr><tr><td>January 2010 - December 2010</td><td>2,000</td><td>$</td><td>51.25</td></tr><tr><td>January 2011 - December 2011</td><td>1,500</td><td>$</td><td>51.25</td></tr><tr><td>January 2012 - February 2012</td><td>1,500</td><td>$</td><td>51.25</td></tr><tr><td rowspan="2">Dates</td><td colspan="2">Volumes (bbl/month)</td><td rowspan="2">Price</td></tr><tr><td>1,500</td><td>$</td></tr><tr><td>January 2010 - December 2010</td><td>1,500</td><td>$</td><td>66.15</td></tr><tr><td>January 2011 - December 2011</td><td>1,500</td><td>$</td><td>66.15</td></tr><tr><td rowspan="2">Dates</td><td colspan="2">Volumes (bbl/month)</td><td rowspan="2">Price</td></tr><tr><td>7,000</td><td>$</td></tr><tr><td>January 2010 - December 2010</td><td>4,000</td><td>$</td><td>82.60</td></tr><tr><td>January 2011 - December 2011</td><td>4,000</td><td>$</td><td>82.60</td></tr><tr><td rowspan="2">Dates</td><td colspan="2">Volumes (bbl/month)</td><td rowspan="2">Price</td></tr><tr><td>3,000</td><td>$</td></tr><tr><td>January 2010 - December 2010</td><td>3,000</td><td>$</td><td>84.25</td></tr><tr><td>January 2011 - December 2011</td><td>1,500</td><td>$</td><td>84.25</td></tr></table>

## Interest Rate Risk

We did not have outstanding any borrowings under our credit facilities or other obligations that would subject us to significant interest rate risk at December 31, 2009. Our Credit Facility entered into with CIT on February 27, 2009, will, however, subject us to interest rate risk on borrowings under that facility.

Our Credit Facility with CIT allows us to fix the interest rate of borrowings under our Credit Facility for all or a portion of the principal balance for a period up to six months. To the extent the interest rate is fixed, interest rate changes affect the instrument’s fair market value but do not impact results of operations or cash flows. Conversely, for the portion of our borrowings that has a floating interest rate, interest rate changes will not affect the fair market value but will impact future results of operations and cash flows.



## Item 8. Financial Statements and Supplementary Data

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

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

None.

## Item 9A. Controls and Procedures

## Evaluation of Disclosure Controls and Procedures

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

As of December 31, 2009, our management, including our Chief Executive Officer and Chief Financial Officer, had evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) pursuant to Rule 13a-15(b) under the Exchange Act. Based upon and as of the date of the evaluation, our Chief Executive Officer and Chief Financial Officer concluded that information required to be disclosed is recorded, processed, summarized and reported within the specified periods and is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, to allow for timely decisions regarding required disclosure of material information required to be included in our periodic SEC reports. Based on the foregoing, our management determined that our disclosure controls and procedures were effective as of December 31, 2009.

## Management’s Annual Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). The design of any system of controls is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions, regardless of how remote. All internal control systems, no matter how well designed, have inherent limitations. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

We carried out an evaluation, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our internal controls over financial reporting as of December 31, 2009. In making this assessment, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in “Internal Control-Integrated Framework.” Based on this assessment, management believes that, as of December 31, 2009, our internal control over financial reporting was effective based on those criteria. There have been no changes in internal control over financial reporting since December 31, 2009, that has materially affected or is reasonably likely to materially affect our internal control over financial reporting.

The effectiveness of our internal control over financial reporting as of December 31, 2009 has been audited by Mantiya McReynolds LLC, an independent registered public accounting firm, as stated in their report which is included herein on the following page.



# REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited Northern Oil and Gas, Inc.'s (the Company) internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management's Annual Report on Internal Control Over Financial Reporting (Item 9A). Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

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

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

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

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the balance sheets of Northern Oil and Gas, Inc. as of December 31, 2009 and 2008, and the related statements of operations, stockholders' equity, and cash flows for each of the years in the three-year period ended December 31, 2009, and our report dated March 8, 2010 expressed an unqualified opinion on those financial statements.

Mantyla McReynolds LLC
Salt Lake City, Utah
March 8, 2010






## PART III

We are incorporating by reference information in Items 10 through 14 below from the definitive proxy statement for our 2010 Annual Meeting of Stockholders, which we intend to file with the SEC not later than 120 days subsequent to December 31, 2009.

## Item 10. Directors, Executive Officers and Corporate Governance

## Executive Officers of the Registrant

Pursuant to Instruction 3 to Item 401(b) of Regulation S-K and General Instruction G(3) to Form 10-K, the following information is included in Part I of this annual report. The following are our executive officers as of March 1, 2010.

<table><tr><td>Name</td><td>Age</td><td>Positions</td></tr><tr><td>Michael L. Reger</td><td>33</td><td>Chairman, Chief Executive Officer and Secretary</td></tr><tr><td>Ryan R. Gilbertson</td><td>33</td><td>Director and Chief Financial Officer</td></tr></table>

Michael L. Reger has served as our Chief Executive Officer, Secretary and a Director since March 2007. Mr. Reger has been primarily involved in the acquisition of oil, gas and mineral rights for his entire professional life and is a director of Reger Oil based in Billings, Montana. Mr. Reger holds a Bachelor of Arts in Finance and an MBA in Finance/Management from the University of St. Thomas in St. Paul, Minnesota. The Reger family has a history of acreage acquisition in the Williston Basin dating to 1952.

Ryan R. Gilbertson has served as our Chief Financial Officer and a Director since March 2007. Mr. Gilbertson’s last position prior to co-founding Northern was at Piper Jaffray in Minneapolis from March 2004 to August 2006. Prior to Piper Jaffray, Ryan was a portfolio manager at Telluride Asset Management, a multi-strategy hedge fund based in Wayzata, Minnesota. Ryan holds a BA from Gustavus Adolphus College in International Business/Finance.

The remaining information required by this Item is incorporated by reference to the definitive proxy statement for our 2010 Annual Meeting of Stockholders, which we intend to file with the SEC not later than 120 days subsequent to December 31, 2009.

We have adopted a Code of Business Conduct and Ethics that applies to our chief executive officer, chief financial officer and persons performing similar functions. A copy is available on our website at www.northernoil.com. We intend to post on our website any amendments to, or waivers from, our Code of Business Conduct and Ethics pursuant to the rules of the SEC and NYSE Amex Equity Market.

## Item 11. Executive Compensation

The information required by this Item is incorporated by reference to the definitive proxy statement for our 2010 Annual Meeting of Stockholders, which we intend to file with the SEC not later than 120 days subsequent to December 31, 2009.



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

## Securities Authorized for Issuance under Equity Compensation Plans

The following table provides information with respect to our common shares issuable under our equity compensation plans as of December 31, 2009:

<table><tr><td>Plan Category</td><td>Number of securities to be issued upon exercise of outstanding options, warrants and rights (a)</td><td>Weighted-average exercise price of outstanding options, warrants and rights (b)</td><td>Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c)</td></tr><tr><td>Equity compensation plans approved by security holders</td><td></td><td></td><td></td></tr><tr><td>2006 Incentive Stock Option Plan</td><td>300,000</td><td>$ 5.18</td><td>340,000</td></tr><tr><td>2009 Equity Incentive Plan</td><td>-</td><td>-</td><td>2,357,084</td></tr><tr><td>Equity compensation plans not approved by security holders</td><td></td><td></td><td></td></tr><tr><td>None</td><td>-</td><td>-</td><td>-</td></tr><tr><td>Total</td><td>300,000</td><td>$ 5.18</td><td>2,697,084</td></tr></table>

The remaining information required by this Item is incorporated by reference to the definitive proxy statement for our 2010 Annual Meeting of Stockholders, which we intend to file with the SEC not later than 120 days subsequent to December 31, 2009.

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

The information required by this Item is incorporated by reference to the definitive proxy statement for our 2010 Annual Meeting of Stockholders, which we intend to file with the SEC not later than 120 days subsequent to December 31, 2009.

## Item 14. Principal Accountant Fees and Services

The information required by this Item is incorporated by reference to the definitive proxy statement for our 2010 Annual Meeting of Stockholders, which we intend to file with the SEC not later than 120 days subsequent to December 31, 2009.



## PART IV

## Item 15. Exhibits and Financial Statement Schedules

(a) Documents filed as Part of this Report:

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

2. Financial Statement Schedules

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

(b) Exhibits:

Unless otherwise indicated, all documents incorporated by reference into this report are filed with the SEC pursuant to the Securities Exchange Act of 1934, as amended, under file number 000-33999.

<table><tr><td>Exhibit No.</td><td>Description</td><td>Reference</td></tr><tr><td>3.1</td><td>Composite Articles of Incorporation of Northern Oil and Gas, Inc.</td><td>Incorporated by reference to Exhibit 3.1 to our company&#x27;s Annual Report on Form 10-K/A (Amendment No. 3) filed with the SEC on June 24, 2009</td></tr><tr><td>3.2</td><td>Amended and Restated Bylaws of Northern Oil and Gas, Inc.</td><td>Incorporated by reference to Exhibit 99.2 to the Registrant&#x27;s Current Report on Form 8-K filed with the SEC on December 6, 2007 (File No. 000-30955)</td></tr><tr><td>4.1</td><td>Specimen Stock Certificate of Northern Oil and Gas, Inc.</td><td>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)</td></tr><tr><td>10.1</td><td>Form of Warrant</td><td>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)</td></tr><tr><td>10.2*</td><td>Amended and Restated Employment Agreement by and between Northern Oil and Gas, Inc. and Michael L. Reger, dated January 30, 2009</td><td>Incorporated by reference to Exhibit 10.2 to the Registrant&#x27;s Current Report on Form 8-K filed with the SEC on February 2, 2009 (File No. 000-30955)</td></tr><tr><td>10.3*</td><td>Amended and Restated Employment Agreement by and between Northern Oil and Gas, Inc. and Ryan R. Gilbertson, dated January 30, 2009</td><td>Incorporated by reference to Exhibit 10.3 to the Registrant&#x27;s Current Report on Form 8-K filed with the SEC on February 2, 2009 (File No. 000-30955)</td></tr><tr><td>10.4</td><td>Irrevocable Proxy Provided by Joseph A. Geraci II, Kimberlie Geraci, Lantern Advisers, LLC, Isles Capital, LLC and Mill City Ventures, LP, dated February 21, 2008</td><td>Incorporated by reference to Exhibit 10.1 to the Registrant&#x27;s Current Report on Form 8-K filed with the SEC on March 19, 2008 (File No. 000-30955)</td></tr><tr><td>10.5</td><td>Agreement by and between Northern Oil and Gas, Inc. and Deephaven MCF Acquisition LLC dated April 14, 2008</td><td>Incorporated by reference to Exhibit 10.1 to the Registrant&#x27;s Current Report on Form 8-K filed with the SEC on April 16, 2008 (File No. 000-30955)</td></tr><tr><td>10.6</td><td>Second Amendment to Agreement by and between Northern Oil and Gas, Inc. and Deephaven MCF Acquisition LLC dated April 14, 2008</td><td>Incorporated by reference to Exhibit 10.1 to the Registrant&#x27;s Current Report on Form 8-K filed with the SEC on September 29, 2008 (File No. 000-30955)</td></tr></table>



<table><tr><td>Exhibit No.</td><td>Description</td><td>Reference</td></tr><tr><td>10.7</td><td>Registration Rights Agreement By and Among Northern Oil and Gas, Inc. and Deephaven MCF Acquisition LLC dated April 14, 2008</td><td>Incorporated by reference to Exhibit 10.2 to the Registrant&#x27;s Current Report on Form 8-K filed with the SEC on April 16, 2008 (File No. 000-30955)</td></tr><tr><td>10.8</td><td>Lease Purchase Agreement By and Between Northern Oil and Gas, Inc. and Woodstone Resources, L.L.C.</td><td>Incorporated by reference to Exhibit 10.1 to the Registrant&#x27;s Current Report on Form 8-K filed with the SEC on June 17, 2008 (File No. 000-30955)</td></tr><tr><td>10.9*</td><td>Northern Oil and Gas, Inc. 2009 Equity Compensation Plan</td><td>Incorporated by reference to Exhibit 10.1 to the Registrant&#x27;s Current Report on Form 8-K filed with the SEC on February 2, 2009 (File No. 000-30955)</td></tr><tr><td>10.10</td><td>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</td><td>Incorporated by reference to Exhibit 10.1 to the Registrant&#x27;s Current Report on Form 8-K filed with the SEC on March 2, 2009 (File No. 000-30955)</td></tr><tr><td>10.11</td><td>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</td><td>Incorporated by reference to Exhibit 10.2 to the Registrant&#x27;s Current Report on Form 8-K filed with the SEC on March 2, 2009 (File No. 000-30955)</td></tr><tr><td>10.12</td><td>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</td><td>Incorporated by reference to Exhibit 10.3 to the Registrant&#x27;s Current Report on Form 8-K filed with the SEC on March 2, 2009 (File No. 000-30955)</td></tr><tr><td>10.13</td><td>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</td><td>Incorporated by reference to Exhibit 10.4 to the Registrant&#x27;s Current Report on Form 8-K filed with the SEC on March 2, 2009 (File No. 000-30955)</td></tr><tr><td>10.14</td><td>Warrant to Purchase Shares of Northern Oil and Gas, Inc. Common Stock Issued to CIT Group/Equity Investments, Inc. on February 27, 2009</td><td>Incorporated by reference to Exhibit 10.5 to the Registrant&#x27;s Current Report on Form 8-K filed with the SEC on March 2, 2009 (File No. 000-30955)</td></tr><tr><td>10.15*</td><td>Northern Oil and Gas, Inc. 2009 Equity Incentive Plan</td><td>Incorporated by reference to Exhibit 10.1 to the Registrant&#x27;s Current Registration Statement on Form S-8 filed with the SEC on July 16, 2009 (File No. 333-160602)</td></tr><tr><td>10.16</td><td>Exploration and Development Agreement dated effective as of April 1, 2009 by and between Slawson Exploration Company, Inc. and Northern Oil and Gas, Inc.</td><td>Incorporated by reference to Exhibit 2.1 to the Registrant&#x27;s Current Report on Form 8-K filed with the SEC on May 29, 2009</td></tr><tr><td>10.17</td><td>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</td><td>Incorporated by reference to Exhibit 10.1 to the Registrant&#x27;s Current Report on Form 8-K filed with the SEC on May 29, 2009</td></tr><tr><td>10.18*</td><td>Form of Promissory Note issued to Michael L. Reger and Ryan R. Gilbertson</td><td>Filed herewith</td></tr><tr><td>10.19*</td><td>Form of Restricted Stock Agreement issued under the Northern Oil and Gas, Inc. 2009 Equity Incentive Plan</td><td>Filed herewith</td></tr></table>



<table><tr><td>18.1</td><td>Letter from Mantyla McReynolds, LLC Regarding Change in Accounting Principles</td><td>Incorporated by reference to Exhibit 18.1 to the Registrant&#x27;s Current Report on Form 10-Q filed with the SEC on October 27, 2009</td></tr><tr><td>23.1</td><td>Consent of Independent Registered Public Accounting Firm Mantyla McReynolds LLC</td><td>Filed herewith</td></tr><tr><td>23.2</td><td>Consent of Ryder Scott Company, LP</td><td>Filed herewith</td></tr><tr><td>31.1</td><td>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</td><td>Filed herewith</td></tr><tr><td>31.2</td><td>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</td><td>Filed herewith</td></tr><tr><td>32.1</td><td>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</td><td>Filed herewith</td></tr><tr><td>99.1</td><td>Report of Ryder Scott Company, LP.</td><td>Filed herewith</td></tr></table>

* 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: March 8, 2010

By: /s/ Michael L. Reger
Michael L. Reger
Chief Executive Officer

## POWER OF ATTORNEY

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

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

<table><tr><td>Signature</td><td>Title</td><td>Date</td></tr><tr><td>/s/ Michael L. Reger</td><td>Chief Executive Officer, Director and Secretary</td><td>March 8, 2010</td></tr><tr><td>Michael L. Reger</td><td></td><td></td></tr><tr><td>/s/ Ryan R. Gilbertson</td><td>Chief Financial Officer, Principal Financial Officer, Principal Accounting Officer, Director</td><td>March 8, 2010</td></tr><tr><td>Ryan R. Gilbertson</td><td></td><td></td></tr><tr><td>/s/ Loren J. O&#x27;Toole</td><td>Director</td><td>March 8, 2010</td></tr><tr><td>Loren J. O&#x27;Toole</td><td></td><td></td></tr><tr><td>/s/ Carter Stewart</td><td>Director</td><td>March 8, 2010</td></tr><tr><td>Carter Stewart</td><td></td><td></td></tr><tr><td>/s/ Jack King</td><td>Director</td><td>March 8, 2010</td></tr><tr><td>Jack King</td><td></td><td></td></tr><tr><td>/s/ Robert Grabb</td><td>Director</td><td>March 8, 2010</td></tr><tr><td>Robert Grabb</td><td></td><td></td></tr><tr><td>/s/ Lisa Bromiley Meier</td><td>Director</td><td>March 8, 2010</td></tr><tr><td>Lisa Bromiley Meier</td><td></td><td></td></tr></table>



## NORTHERN OIL AND GAS, INC.

## INDEX TO FINANCIAL STATEMENTS

<table><tr><td></td><td>Page</td></tr><tr><td>Report of Independent Registered Public Accounting Firm</td><td>F-2</td></tr><tr><td>Balance Sheets as of December 31, 2009 and 2008</td><td>F-3</td></tr><tr><td>Statements of Operations for the Years Ended December 31, 2009, December 31, 2008 and December 31, 2007</td><td>F-4</td></tr><tr><td>Statements of Stockholders&#x27; Equity for the Years Ended December 31, 2009, December 31, 2008 and December 31, 2007</td><td>F-5</td></tr><tr><td>Statements of Cash Flows for the Years Ended December 31, 2009, December 31, 2008 and December 31, 2007</td><td>F-6</td></tr><tr><td>Notes to the Financial Statements</td><td>F-7</td></tr></table>



# 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, 2009 and 2008, and the related statements of operations, stockholders' equity, and cash flows for each of the years in the three-year period ended December 31, 2009. 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, 2009 and 2008, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2009 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, 2009, 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 8, 2010 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

As discussed in Note 2 to the financial statements, the Company has elected to change its method of accounting for accrued drilling costs in 2009.

Mantyla McReynolds LLC

Salt Lake City, Utah

March 8, 2010



## NORTHERN OIL AND GAS, INC.
BALANCE SHEETS
DECEMBER 31, 2009 AND 2008

<table><tr><td colspan="3">ASSETS</td></tr><tr><td colspan="3">Year Ended December 31,</td></tr><tr><td></td><td>2009</td><td>2008</td></tr><tr><td></td><td></td><td>Adjusted*</td></tr><tr><td>CURRENT ASSETS</td><td></td><td></td></tr><tr><td>Cash and Cash Equivalents</td><td>$ 6,233,372</td><td>$ 780,716</td></tr><tr><td>Trade Receivables</td><td>7,025,011</td><td>2,028,941</td></tr><tr><td>Other Receivables</td><td>-</td><td>874,453</td></tr><tr><td>Prepaid Drilling Costs</td><td>1,454,034</td><td>4,549</td></tr><tr><td>Prepaid Expenses</td><td>143,606</td><td>71,554</td></tr><tr><td>Other Current Assets</td><td>201,314</td><td>-</td></tr><tr><td>Short - Term Investments</td><td>24,903,476</td><td>-</td></tr><tr><td>Deferred Tax Asset</td><td>2,057,000</td><td>1,390,000</td></tr><tr><td>Total Current Assets</td><td>42,017,813</td><td>5,150,213</td></tr><tr><td colspan="3">PROPERTY AND EQUIPMENT</td></tr><tr><td colspan="3">Oil and Natural Gas Properties, Full Cost Method (including unevaluated cost of</td></tr><tr><td>$53,862,529 at 12/31/09 and $35,990,267 at 12/31/2008)</td><td>96,801,626</td><td>47,260,838</td></tr><tr><td>Other Property and Equipment</td><td>439,656</td><td>408,400</td></tr><tr><td>Total Property and Equipment</td><td>97,241,282</td><td>47,669,238</td></tr><tr><td>Less - Accumulated Depreciation and Depletion</td><td>5,091,198</td><td>748,421</td></tr><tr><td>Total Property and Equipment, Net</td><td>92,150,084</td><td>46,920,817</td></tr><tr><td>LONG - TERM INVESTMENTS</td><td>-</td><td>2,416,369</td></tr><tr><td>DEBT ISSUANCE COSTS</td><td>1,427,071</td><td>-</td></tr><tr><td>DEFERRED TAX ASSET</td><td>-</td><td>33,000</td></tr><tr><td>Total Assets</td><td>$ 135,594,968</td><td>$ 54,520,399</td></tr><tr><td colspan="3">LIABILITIES AND STOCKHOLDERS&#x27; EQUITY</td></tr><tr><td>CURRENT LIABILITIES</td><td></td><td></td></tr><tr><td>Accounts Payable</td><td>$ 6,419,534</td><td>$ 1,934,810</td></tr><tr><td>Line of Credit</td><td>834,492</td><td>1,650,720</td></tr><tr><td>Accrued Expenses</td><td>316,977</td><td>1,270,075</td></tr><tr><td>Derivative Liability</td><td>1,320,679</td><td>-</td></tr><tr><td>Other Liabilities</td><td>18,574</td><td>18,574</td></tr><tr><td>Total Current Liabilities</td><td>8,910,256</td><td>4,874,179</td></tr><tr><td>LONG-TERM LIABILITIES</td><td></td><td></td></tr><tr><td>Revolving Line of Credit</td><td>-</td><td>-</td></tr><tr><td>Derivative Liability</td><td>1,459,374</td><td>-</td></tr><tr><td>Subordinated Notes</td><td>500,000</td><td>-</td></tr><tr><td>Other Noncurrent Liabilities</td><td>243,888</td><td>117,157</td></tr><tr><td>Total Long-Term Liabilities</td><td>2,203,262</td><td>117,157</td></tr><tr><td>DEFERRED TAX LIABILITY</td><td>922,000</td><td>-</td></tr><tr><td>Total Liabilities</td><td>12,035,518</td><td>4,991,336</td></tr><tr><td>STOCKHOLDERS&#x27; EQUITY</td><td></td><td></td></tr><tr><td>Common Stock, Par Value \(.001; 100,000,000 Authorized, 43,911,044 Outstanding (2008 - 34,120,103 Shares Outstanding)</td><td>43,912</td><td>34,121</td></tr><tr><td>Additional Paid-In Capital</td><td>124,884,266</td><td>51,692,776</td></tr><tr><td>Retained Earnings (Accumulated Deficit)</td><td>841,892</td><td>(1,957,060)</td></tr><tr><td>Accumulated Other Comprehensive Income (Loss)</td><td>(2,210,620)</td><td>(240,774)</td></tr><tr><td>Total Stockholders&#x27; Equity</td><td>123,559,450</td><td>49,529,063</td></tr><tr><td>Total Liabilities and Stockholders&#x27; Equity</td><td>$ 135,594,968</td><td>$ 54,520,399</td></tr></table>

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



## NORTHERN OIL AND GAS, INC.
STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 2009, 2008, AND 2007

<table><tr><td rowspan="3"></td><td colspan="3">Year Ended December 31,</td></tr><tr><td>2009</td><td>2008</td><td>2007</td></tr><tr><td colspan="2">Adjusted *</td><td></td></tr><tr><td>REVENUES</td><td></td><td></td><td></td></tr><tr><td>Oil and Gas Sales</td><td>$ 15,171,824</td><td>$ 3,542,994</td><td>$ -</td></tr><tr><td>Gain (Loss) on Settled Derivatives</td><td>(624,541)</td><td>778,885</td><td>-</td></tr><tr><td>Mark-to-Market of Derivative Instruments</td><td>(363,414)</td><td></td><td></td></tr><tr><td>Other Revenue</td><td>37,630</td><td>-</td><td>-</td></tr><tr><td></td><td>14,221,499</td><td>4,321,879</td><td>-</td></tr><tr><td>OPERATING EXPENSES</td><td></td><td></td><td></td></tr><tr><td>Production Expenses</td><td>754,976</td><td>70,954</td><td>-</td></tr><tr><td>Production Taxes</td><td>1,300,373</td><td>203,182</td><td>-</td></tr><tr><td>General and Administrative Expense</td><td>2,452,823</td><td>1,985,914</td><td>1,754,826</td></tr><tr><td>Share Based Compensation</td><td>1,233,507</td><td>105,375</td><td>2,754,917</td></tr><tr><td>Depletion of Oil and Gas Properties</td><td>4,250,983</td><td>677,915</td><td>-</td></tr><tr><td>Depreciation and Amortization</td><td>91,794</td><td>67,060</td><td>3,446</td></tr><tr><td>Accretion of Discount on Asset Retirement Obligations</td><td>8,082</td><td>1,030</td><td>-</td></tr><tr><td>Total Expenses</td><td>10,092,538</td><td>3,111,430</td><td>4,513,189</td></tr><tr><td>INCOME (LOSS) FROM OPERATIONS</td><td>4,128,961</td><td>1,210,449</td><td>(4,513,189)</td></tr><tr><td>OTHER INCOME</td><td>135,991</td><td>383,891</td><td>207,896</td></tr><tr><td>INCOME (LOSS) BEFORE INCOME TAXES</td><td>4,264,952</td><td>1,594,340</td><td>(4,305,293)</td></tr><tr><td>INCOME TAX PROVISION (BENEFIT)</td><td>1,466,000</td><td>(830,000)</td><td>-</td></tr><tr><td>NET INCOME (LOSS)</td><td>$ 2,798,952</td><td>$ 2,424,340</td><td>$ (4,305,293)</td></tr><tr><td></td><td></td><td></td><td></td></tr><tr><td>Net Income (Loss) Per Common Share - Basic</td><td>$ 0.08</td><td>$ 0.08</td><td>$ (0.18)</td></tr><tr><td>Net Income (Loss) Per Common Share - Diluted</td><td>$ 0.08</td><td>$ 0.07</td><td>$ (0.18)</td></tr><tr><td>Weighted Average Shares Outstanding - Basic</td><td>36,705,267</td><td>31,920,747</td><td>23,667,119</td></tr><tr><td>Weighted Average Shares Outstanding - Diluted</td><td>36,877,070</td><td>32,653,552</td><td>23,667,119</td></tr></table>

 \( ^{*} \) See Note 2

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



## NORTHERN OIL AND GAS, INC.
STATEMENT OF STOCKHOLDERS' EQUITY (DEFICIT)
FOR THE YEARS ENDED DECEMBER 31, 2009, 2008, AND 2007

<table><tr><td rowspan="3"></td><td colspan="8">Accumulated</td></tr><tr><td colspan="3">Additional</td><td rowspan="2">Stock Subscriptions Receivable</td><td rowspan="2">Income (Loss)</td><td rowspan="2">Retained Earnings (Accumulated Deficit)</td><td rowspan="2">Total Stockholders&#x27; Equity (Deficit)</td><td></td></tr><tr><td>Common Stock</td><td>Paid-In Capital</td><td></td></tr><tr><td>Balance - December 31, 2006</td><td>18,000,000</td><td>$ 1,800</td><td>$ 38,575</td><td>$ (1,400)</td><td>$ -</td><td>$ (76,107)</td><td>$ (37,132)</td><td></td></tr><tr><td>Payment on Stock Subscriptions Receivable</td><td>-</td><td>-</td><td>-</td><td>1,400</td><td>-</td><td>-</td><td>1,400</td><td></td></tr><tr><td>Sale of 2,501,573 Common Shares for $1.05 Per Share</td><td>2,501,573</td><td>250</td><td>2,626,402</td><td>-</td><td>-</td><td>-</td><td>2,626,652</td><td></td></tr><tr><td>Private Placement Costs</td><td>-</td><td>-</td><td>(9,933)</td><td>-</td><td>-</td><td>-</td><td>(9,933)</td><td></td></tr><tr><td>Issued 400,000 Common Shares to Montana Oil and Gas, Inc. for Leasehold Interest</td><td>400,000</td><td>40</td><td>419,960</td><td>-</td><td>-</td><td>-</td><td>420,000</td><td></td></tr><tr><td>Issued 271,440 Shares to Southfork Exploration, LLC</td><td>271,440</td><td>27</td><td>284,985</td><td>-</td><td>-</td><td>-</td><td>285,012</td><td></td></tr><tr><td>Balance Immediately Prior to Reverse Acquisition with Kentex</td><td>21,173,013</td><td>2,117</td><td>3,359,989</td><td>-</td><td>-</td><td>(76,107)</td><td>3,285,999</td><td></td></tr><tr><td>Reverse Acquisition with Kentex:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Recapitalization of NOG with Kentex Common</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Stock Issued in the Acquisition (Par Value)</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Changed to $.001 Per Share)</td><td>-</td><td>19,056</td><td>(19,056)</td><td>-</td><td>-</td><td>-</td><td>-</td><td></td></tr><tr><td>Acquisition of Kentex</td><td>1,491,110</td><td>1,491</td><td>(1,491)</td><td>-</td><td>-</td><td>-</td><td>-</td><td></td></tr><tr><td>Legal Fees</td><td>-</td><td>-</td><td>(25,000)</td><td>-</td><td>-</td><td>-</td><td>(25,000)</td><td></td></tr><tr><td>Introduction Fee</td><td>-</td><td>-</td><td>(12,500)</td><td>-</td><td>-</td><td>-</td><td>(12,500)</td><td></td></tr><tr><td>Payment to Kentex Stockholders</td><td>-</td><td>-</td><td>(377,500)</td><td>-</td><td>-</td><td>-</td><td>(377,500)</td><td></td></tr><tr><td>Other Professional Fees</td><td>-</td><td>-</td><td>(36,062)</td><td>-</td><td>-</td><td>-</td><td>(36,062)</td><td></td></tr><tr><td>Totals of Reverse Acquisition</td><td>1,491,110</td><td>20,547</td><td>(471,609)</td><td>-</td><td>-</td><td>-</td><td>(451,062)</td><td></td></tr><tr><td>Balance Immediately After Reverse Acquisition with Kentex</td><td>22,664,123</td><td>22,664</td><td>2,888,380</td><td>-</td><td>-</td><td>(76,107)</td><td>2,834,937</td><td></td></tr><tr><td>Issued 173,500 Shares for Consulting Fees (Value between $4.75 and $5.18 per Common Share)</td><td>173,500</td><td>174</td><td>855,556</td><td>-</td><td>-</td><td>-</td><td>855,730</td><td></td></tr><tr><td>Compensation Related Stock Option Grants</td><td>-</td><td>-</td><td>2,366,417</td><td>-</td><td>-</td><td>-</td><td>2,366,417</td><td></td></tr><tr><td>Sale of 4,545,455 Common Shares for $3.30 Per Share (unit placement)</td><td>4,545,455</td><td>4,545</td><td>14,995,457</td><td>-</td><td>-</td><td>-</td><td>15,000,002</td><td></td></tr><tr><td>Private Placement Costs net of Warrants Granted to Agent</td><td>-</td><td>-</td><td>(1,191,000)</td><td>-</td><td>-</td><td>-</td><td>(1,191,000)</td><td></td></tr><tr><td>Issued 390,000 Common Shares for Leasehold Interest</td><td>390,000</td><td>390</td><td>1,957,410</td><td>-</td><td>-</td><td>-</td><td>1,957,800</td><td></td></tr><tr><td>Issued 75,000 Shares as Compensation</td><td>75,000</td><td>75</td><td>388,425</td><td>-</td><td>-</td><td>-</td><td>388,500</td><td></td></tr><tr><td>Repurchase of 152,156 Common Shares</td><td>(152,156)</td><td>(152)</td><td>(1,049,724)</td><td>-</td><td>-</td><td>-</td><td>(1,049,876)</td><td></td></tr><tr><td>Issued Pursuant to Exercise of Options</td><td>1,000,000</td><td>1,000</td><td>1,049,000</td><td>-</td><td>-</td><td>-</td><td>1,050,000</td><td></td></tr><tr><td>Net Income (Loss)</td><td>-</td><td>-</td><td>-</td><td>-</td><td>-</td><td>-</td><td>(4,305,293)</td><td>(4,305,293)</td></tr><tr><td>Balance - December 31, 2007</td><td>28,695,922</td><td>28,696</td><td>22,259,921</td><td>-</td><td>-</td><td>-</td><td>(4,381,400)</td><td>17,907,217</td></tr></table>



<table><tr><td>Issued 7,500 Common Shares for services</td><td>7,500</td><td>8</td><td>49,867</td><td>-</td><td>-</td><td>-</td><td>49,875</td></tr><tr><td>Issued 318,495 Common Shares for Leasehold Interest</td><td>318,495</td><td>319</td><td>2,084,053</td><td>-</td><td>-</td><td>-</td><td>2,084,372</td></tr><tr><td>(Value between $2.30 and $11.98 per Common Share)</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Issued 20,000 Common Shares of Restricted Stock for employee services</td><td>20,000</td><td>20</td><td>(20)</td><td>-</td><td>-</td><td>-</td><td>-</td></tr><tr><td>Listing Fee Paid to American Stock Exchange</td><td>-</td><td>-</td><td>(65,000)</td><td>-</td><td>-</td><td>-</td><td>(65,000)</td></tr><tr><td>Issued Pursuant to Exercise of Options</td><td>260,000</td><td>260</td><td>933,540</td><td>-</td><td>-</td><td>-</td><td>933,800</td></tr><tr><td>Issued Pursuant to Exercise of Warrants</td><td>4,818,186</td><td>4,818</td><td>25,977,244</td><td>-</td><td>-</td><td>-</td><td>25,982,062</td></tr><tr><td>Warrant Exercise Costs</td><td>-</td><td>-</td><td>(77,204)</td><td>-</td><td>-</td><td>-</td><td>(77,204)</td></tr><tr><td>Stock Grant Compensation</td><td>-</td><td>-</td><td>105,375</td><td>-</td><td>-</td><td>-</td><td>105,375</td></tr><tr><td>Unrealized Losses on Auction Rate Securities</td><td>-</td><td>-</td><td>-</td><td>-</td><td>(240,774)</td><td>-</td><td>(240,774)</td></tr><tr><td>Income Tax Benefit from Options Exercised</td><td>-</td><td>-</td><td>425,000</td><td>-</td><td>-</td><td>-</td><td>425,000</td></tr><tr><td>Net Income - As Adjusted</td><td>-</td><td>-</td><td>-</td><td>-</td><td>-</td><td>2,424,340</td><td>2,424,340</td></tr><tr><td>Balance - December 31, 2008</td><td>$ 34,120,103</td><td>$ 34,121</td><td>$ 51,692,776</td><td>$</td><td>$ (240,774)</td><td>$ (1,957,060)</td><td>$ 49,529,063</td></tr><tr><td>Warrants Issued Included for Debt Issuance Costs</td><td>-</td><td>-</td><td>221,153</td><td>-</td><td>-</td><td>-</td><td>221,153</td></tr><tr><td>Stock Grant Compensation</td><td>-</td><td>-</td><td>366,690</td><td>-</td><td>-</td><td>-</td><td>366,690</td></tr><tr><td>Net Change in Cash Flow Hedge Derivatives</td><td>-</td><td>-</td><td>-</td><td>-</td><td>(1,483,639)</td><td>-</td><td>(1,483,639)</td></tr><tr><td>Unrealized Gain on Short-Term Investments</td><td>-</td><td>-</td><td>-</td><td>-</td><td>(486,207)</td><td>-</td><td>(486,207)</td></tr><tr><td>Issued 180,000 shares as Debt Insurance Costs</td><td>180,000</td><td>180</td><td>475,020</td><td>-</td><td>-</td><td>-</td><td>475,200</td></tr><tr><td>Issued 283,670 Shares as Compensation/Director Fees (Value between $2.84 and $9.70 per Common Share)</td><td>283,670</td><td>284</td><td>2,092,695</td><td>-</td><td>-</td><td>-</td><td>2,092,979</td></tr><tr><td>Sale of 2,250,000 Common Shares for $6.00 Per Share</td><td>2,250,000</td><td>2,250</td><td>13,497,750</td><td>-</td><td>-</td><td>-</td><td>13,500,000</td></tr><tr><td>Sale of 6,500,000 Common Shares for $9.12 Per Share</td><td>6,500,000</td><td>6,500</td><td>59,273,500</td><td>-</td><td>-</td><td>-</td><td>59,280,000</td></tr><tr><td>Issued 128,097 Common Shares for Leasehold Interest (Value between $4.25 and $11.46 per Common Share)</td><td>128,097</td><td>128</td><td>1,115,610</td><td>-</td><td>-</td><td>-</td><td>1,115,738</td></tr><tr><td>Repurchase of 2,084 Common Shares</td><td>(2,084)</td><td>(2)</td><td>(20,213)</td><td>-</td><td>-</td><td>-</td><td>(20,215)</td></tr><tr><td>Costs of Capital Raise</td><td>-</td><td>-</td><td>(3,785,264)</td><td>-</td><td>-</td><td>-</td><td>(3,785,264)</td></tr><tr><td>Issued 361,330 Common Shares of Restricted Stock</td><td>361,330</td><td>361</td><td>(361)</td><td>-</td><td>-</td><td>-</td><td>-</td></tr><tr><td>Repurchase of 52,061 Common Shares</td><td>(52,061)</td><td>(52)</td><td>(517,948)</td><td>-</td><td>-</td><td>-</td><td>(518,000)</td></tr><tr><td>Issued Pursuant to Exercise of Options</td><td>100,000</td><td>100</td><td>517,900</td><td>-</td><td>-</td><td>-</td><td>518,000</td></tr><tr><td>Share Adjustment Related to Kentex Transaction</td><td>41,989</td><td>42</td><td>(42)</td><td>-</td><td>-</td><td>-</td><td>-</td></tr><tr><td>Income Tax Provision for Share Based Compensation</td><td>-</td><td>-</td><td>(45,000)</td><td>-</td><td>-</td><td>-</td><td>(45,000)</td></tr><tr><td>Net Income</td><td>-</td><td>-</td><td>-</td><td>-</td><td>-</td><td>2,798,952</td><td>2,798,952</td></tr></table>



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

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



## NORTHERN OIL AND GAS, INC.
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2009, 2008, AND 2007

<table><tr><td rowspan="3"></td><td colspan="4">Year Ended December 31,</td></tr><tr><td rowspan="2">2009</td><td>2008</td><td rowspan="2">2007</td><td></td></tr><tr><td>Adjusted *</td><td></td></tr><tr><td>CASH FLOWS FROM OPERATING ACTIVITIES</td><td></td><td></td><td></td><td></td></tr><tr><td>Net Income (Loss)</td><td>$ 2,798,952</td><td>$ 2,424,340</td><td>$ (4,305,293)</td><td></td></tr><tr><td>Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by (Used for) Operating Activities:</td><td></td><td></td><td></td><td></td></tr><tr><td>Depletion of Oil and Gas Properties</td><td>4,250,983</td><td>677,915</td><td>-</td><td></td></tr><tr><td>Depreciation and Amortization</td><td>91,794</td><td>67,060</td><td>3,446</td><td></td></tr><tr><td>Amortization of Debt Issuance Costs</td><td>459,343</td><td></td><td></td><td></td></tr><tr><td>Accretion of Discount on Asset Retirement Obligations</td><td>8,082</td><td>1,030</td><td>-</td><td></td></tr><tr><td>Income Tax Provision (Benefit)</td><td>1,466,000</td><td>(830,000)</td><td>-</td><td></td></tr><tr><td>Issuance of Stock for Consulting Fees</td><td>-</td><td>49,875</td><td>855,730</td><td></td></tr><tr><td>Loss on Sale of Available for Sale Securities</td><td>-</td><td>381</td><td>-</td><td></td></tr><tr><td>Market Value adjustment of Derivative Instruments</td><td>363,414</td><td>(95,148)</td><td>-</td><td></td></tr><tr><td>Lease Incentives Received</td><td>-</td><td>91,320</td><td></td><td></td></tr><tr><td>Amortization of Deferred Rent</td><td>(18,573)</td><td>(17,026)</td><td>-</td><td></td></tr><tr><td>Share - Based Compensation Expense</td><td>1,213,292</td><td>105,375</td><td>2,754,917</td><td></td></tr><tr><td>Changes in Working Capital and Other Items:</td><td></td><td></td><td></td><td></td></tr><tr><td>Increase in Trade Receivables</td><td>(4,996,070)</td><td>(2,028,941)</td><td>-</td><td></td></tr><tr><td>Increase (Decrease) in Other Receivables</td><td>874,453</td><td>(874,453)</td><td>-</td><td></td></tr><tr><td>Increase in Prepaid Expenses</td><td>(72,052)</td><td>(45,874)</td><td>(24,556)</td><td></td></tr><tr><td>Increase in Other Current Assets</td><td>(158,334)</td><td>-</td><td>-</td><td></td></tr><tr><td>Increase in Accounts Payable</td><td>4,484,724</td><td>1,821,556</td><td>113,254</td><td></td></tr><tr><td>Increase (Decrease) in Accrued Expenses</td><td>(953,098)</td><td>1,159,082</td><td>110,993</td><td></td></tr><tr><td>Net Cash Provided By (Used For) Operating Activities</td><td>9,812,910</td><td>2,506,492</td><td>(491,509)</td><td></td></tr><tr><td>CASH FLOWS FROM INVESTING ACTIVITIES</td><td></td><td></td><td></td><td></td></tr><tr><td>Purchases of Office Equipment and Furniture</td><td>(31,256)</td><td>(363,631)</td><td>(44,769)</td><td></td></tr><tr><td>Decrease (Increase) in Prepaid Drilling Costs</td><td>(1,449,485)</td><td>359,741</td><td>(364,290)</td><td></td></tr><tr><td>Proceeds from Sale of Oil and Gas Properties</td><td>-</td><td>468,609</td><td>-</td><td></td></tr><tr><td>Purchase of Available for Sale Securities</td><td>(24,106,294)</td><td>(3,800,524)</td><td>-</td><td></td></tr><tr><td>Proceeds from Sale of Available for Sale Securities</td><td>800,000</td><td>975,000</td><td>-</td><td></td></tr><tr><td>Increase in Oil and Gas Properties</td><td>(47,061,666)</td><td>(37,997,157)</td><td>(4,669,699)</td><td></td></tr><tr><td>Net Cash Used For Investing Activities</td><td>(71,848,701)</td><td>(40,357,962)</td><td>(5,078,758)</td><td></td></tr><tr><td>CASH FLOWS FROM FINANCING ACTIVITIES</td><td></td><td></td><td></td><td></td></tr><tr><td>Increase in Margin Loan</td><td>-</td><td>1,650,720</td><td>-</td><td></td></tr><tr><td>Payments on Line of Credit</td><td>(816,228)</td><td>-</td><td>-</td><td></td></tr><tr><td>Advances on Revolving Credit Facility</td><td>29,750,000</td><td>-</td><td>-</td><td></td></tr><tr><td>Repayments on Revolving Credit Facility</td><td>(29,750,000)</td><td>-</td><td>-</td><td></td></tr><tr><td>Repayments of Convertible Notes Payable (Related Party)</td><td>-</td><td>-</td><td>(165,000)</td><td></td></tr><tr><td>Cash Paid for Listing Fee</td><td>-</td><td>(65,000)</td><td>-</td><td></td></tr><tr><td>Proceeds from Derivatives</td><td>-</td><td>95,148</td><td>-</td><td></td></tr><tr><td>Increase in Subordinated Notes, net</td><td>500,000</td><td>-</td><td></td><td></td></tr><tr><td>Debt Issuance Costs Paid</td><td>(1,190,061)</td><td>-</td><td>-</td><td></td></tr><tr><td>Proceeds from the Issuance of Common Stock - Net of Issuance Costs</td><td>68,994,736</td><td>25,904,858</td><td>14,997,992</td><td></td></tr><tr><td>Proceeds from Exercise of Stock Options</td><td>-</td><td>933,800</td><td>-</td><td></td></tr><tr><td>Net Cash Provided by Financing Activities</td><td>67,488,447</td><td>28,519,526</td><td>14,832,992</td><td></td></tr><tr><td>NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS</td><td>5,452,656</td><td>(9,331,944)</td><td>9,262,725</td><td></td></tr><tr><td>CASH AND CASH EQUIVALENTS - BEGINNING OF PERIOD</td><td>780,716</td><td>10,112,660</td><td>849,935</td><td></td></tr><tr><td>CASH AND CASH EQUIVALENTS - END OF PERIOD</td><td>$ 6,233,372</td><td>$ 780,716</td><td>$ 10,112,660</td><td></td></tr><tr><td>Supplemental Disclosure of Cash Flow Information</td><td></td><td></td><td></td><td></td></tr><tr><td>Cash Paid During the Period for Interest</td><td>$ 624,717</td><td>$ -</td><td>$ -</td><td></td></tr><tr><td>Cash Paid During the Period for Income Taxes</td><td>$ -</td><td>$ -</td><td>$ -</td><td></td></tr><tr><td>Non-Cash Financing and Investing Activities:</td><td></td><td></td><td></td><td></td></tr><tr><td>Purchase of Oil and Gas Properties through Issuance of Common Stock</td><td>$ 1,115,738</td><td>$ 2,084,372</td><td>$ 2,662,812</td><td></td></tr><tr><td>Payment of Consulting Fees through Issuance of Common Stock</td><td>$ -</td><td>$ 49,875</td><td>$ 855,730</td><td></td></tr></table>



<table><tr><td>Payment of Compensation through Issuance of Common Stock</td><td>$ 1,213,292</td><td>$ -</td><td>$ 388,500</td></tr><tr><td>Capitalized Asset Retirement Obligations</td><td>$ 137,222</td><td>$ 60,407</td><td>$ -</td></tr><tr><td>Cashless Exercise of Stock Options</td><td>$ 518,000</td><td>$ -</td><td>$ 1,050,000</td></tr><tr><td>Fair Value of Warrants Issued for Debt Issuance Costs</td><td>$ 221,153</td><td>$ -</td><td>$ -</td></tr><tr><td>Payment of Debt Issuance Costs through Issuance of Common Stock</td><td>$ 475,200</td><td>$ -</td><td>$ -</td></tr></table>

 \( ^{*} \)  See Note 2

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



# NORTHERN OIL AND GAS, INC.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2009

## NOTE 1 ORGANIZATION AND NATURE OF BUSINESS

Northern Oil and Gas, Inc. (the "Company," "we," "us," "our" and words of similar import) is a growth-oriented independent energy company engaged in the acquisition, exploration, exploitation and development of oil and natural gas properties. Prior to March 20, 2007, our name was "Kentex Petroleum, Inc." The Company took its present form on March 20, 2007, when Kentex completed a so-called short-form merger with its wholly-owned subsidiary, Northern Oil and Gas, Inc. ("NOG"), a Nevada corporation engaged in the Company's current business, in which NOG merged into Kentex and Kentex was the surviving entity. The Company's common stock trades on the American Stock Exchange under the symbol "NOG".

The Company will continue to focus on projects in the oil and gas industry primarily based in the Rocky Mountains and specifically the Williston Basin Bakken Shale formation. The Company has begun to develop its substantial leasehold in the Bakken play and will continue to do so as well as target additional opportunities in emerging plays utilizing its first mover leasing advantage. The Company participates on a heads up basis in the drilling of wells on our leasehold. The Company owns working interest in wells, and does not lease land to operators. To this point we have participated only in wells operated by others but have a substantial inventory of high working interest locations that we have begun to develop. We believe the advantage gained by participating as a non-operating partner in approximately 179 gross oil wells completed as of December 31, 2009 has given us valuable data on completions and will help our operating partners control well costs and enhance results as we continue to develop our higher working interest sections in 2010 and beyond.

The Company participates on a heads up basis proportionate to its working interest in a declared drilling unit. Although to this point we have participated with interests ranging from approximately 1% to 61%, we expect to participate in incrementally higher working interest drilling units. Our current North Dakota and Montana acreage position in the growing Williston Basin Bakken and Three Forks Play exposes us to approximately 162 net wells based on 640 acre spacing units and 255 net wells based on 320 acre spacing units. With 320-acre spacing units we have the ability to drill approximately 578 net wells, including 255 net wells targeting the Bakken formation, 255 net wells targeting the Three Forks formation and 68 net wells targeting the Red River formation.

Our 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 as well as to carry out the principal and necessary functions incidental to the oil and gas business. With the additional acquisition of 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 oil and gas producer, the Company’s revenue, profitability and future rate of growth are substantially dependent on prevailing prices of natural gas and oil. Historically, the energy markets have been very volatile and it is likely that oil and gas prices will continue to be subject to wide fluctuations in the future. A substantial or extended decline in natural gas and oil 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 oil reserves that can be economically produced.

## NOTE 2 SIGNIFICANT ACCOUNTING POLICIES

These financial statements have been prepared in accordance with generally accepted accounting principles 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. Our cash positions represent assets held in checking and money market accounts. These assets are generally available to us on a daily or weekly basis and are highly liquid in nature. Due to the balances being greater than $250,000, we do not have FDIC coverage on the entire amount of bank deposits. The company believes this risk is minimal. In addition, we are subject to Security Investor Protection Corporation (SIPC) protection on a vast majority of our 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). When securities are sold, their cost is determined based on the first-in first-out method. The realized gains and losses related to these securities are included in other income in the statements of operations.

## Other Property and Equipment

Property and equipment that are not oil and gas properties are recorded at cost and depreciated using the straight-line method over their estimated useful lives of three to five years. Expenditures for replacements, renewals, and betterments are capitalized. Maintenance and repairs are charged to operations as incurred. Long-lived assets, other than oil and gas properties, are evaluated for impairment to determine if current circumstances and market conditions indicate the carrying amount may not be recoverable. We have not recognized any impairment losses on non oil and gas long-lived assets. Depreciation expense was $91,794, $67,070, and $3,446 for the years ended December 31, 2009, 2008, and 2007.

## 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 can exercise these warrants at any time until the warrants expire in February 2012. The exercise price of the warrants is $5.00 per warrant. The total amount capitalized for Debt Issuance Costs is $1,670,000. The capitalized costs are being amortized for three years over the term of the facility using the effective interest method. In May 2009, the Company amended the revolving credit facility with CIT to allow for additional borrowings. The Company incurred $216,414 of direct costs related to this amendment. The capitalized costs will be amortized over the remaining term of the facility using the effective interest method.

The amortization of debt issuance costs for the year ended December 31, 2009 was $459,343.

## 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 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 Gas Balancing

We recognize oil and gas revenues from our 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. We use the sales method of accounting for gas balancing of 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, 2009 and 2008, our gas production was in balance, i.e., our cumulative portion of gas production taken and sold from wells in which we have an interest equaled our entitled interest in gas production from those wells.



## Stock-Based Compensation

The Company has accounted for stock-based compensation under the provisions of FASB Accounting Standards Codification (ASC) 718-10-55 (Prior authoritative literature: FASB Statement 123(R), Share-Based Payment). This statement requires us to record an expense associated with the fair value of stock-based compensation. We use 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 (Prior authoritative literature, FASB Statement 109, Accounting for Income Taxes). Deferred income tax assets and liabilities are determined based upon differences between the financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse. Accounting standards require the consideration of a valuation allowance for deferred tax assets if it is “more likely than not” that some component or all of the benefits of deferred tax assets will not be realized.

## 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 on 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 (Prior authoritative literature, EITF 96-18, Accounting for Equity Instruments That Are Issued to Other Than Employees for Acquiring or in Conjunction with Selling, Goods, or Services).

## Net Income (Loss) Per Common Share

Net Income (Loss) per common share is based on the Net Income (Loss) divided by weighted average number of common shares outstanding.

Diluted earnings per share are computed using weighted average number of common shares plus dilutive common share equivalents outstanding during the period using the treasury stock method. As the Company has a loss for the period ended December 31, 2007 the potentially dilutive shares were anti-dilutive and were thus not added into the earnings per share calculation.

## Full Cost Method

The Company follows the full cost method of accounting for oil and gas operations whereby all costs related to the exploration and development of oil and 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, 2009, 2008, and 2007:



<table><tr><td rowspan="2"></td><td colspan="4">Year Ended December 31,</td></tr><tr><td>2009</td><td>2008</td><td>2007</td><td></td></tr><tr><td>Capitalized Certain Payroll and Other Internal Costs</td><td>$ 2,616,262</td><td>$ 1,374,071</td><td>$ -</td><td></td></tr><tr><td>Capitalized Interest Costs</td><td>624,717</td><td>-</td><td>-</td><td></td></tr><tr><td>Total</td><td>$ 3,240,979</td><td>$ 1,374,071</td><td>$ -</td><td></td></tr></table>

As of December 31, 2009 we controlled acreage in Sheridan County, Montana with primary targets including the Red River and Mission Canyon. We controlled acreage in North Dakota, primarily in Mountrail County, targeting the Bakken Shale and Three Forks/Sanish as well as acreage in Yates County, New York that is prospective for Marcellus Shale and Trenton-Black River 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 year ended December 31, 2008, the Company sold acreage for $468,609. The proceeds for these sales were applied to reduce the capitalized costs of oil and 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 (Prior authoritative literature:, FASB Statement 143, Accounting for Asset Retirement Obligations) 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.

Capitalized costs of oil and 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 oil and gas reserves plus the cost of unevaluated 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 12-month average price of oil and natural gas to estimated future production of proved oil and 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. To this point the Company has not realized any impairment of its properties due to our low basis in the acreage and productivity and economics of our 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 oil and natural gas reserve volumes, future development costs, estimates relating to certain oil and natural gas revenues and expenses, fair value of derivative instruments, fair value of certain investments, and deferred income taxes. Actual results may differ from those estimates.



## Reclassifications

Certain reclassifications have been made to prior years' reported amounts in order to conform with the current year presentation. These reclassifications did not impact our 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 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 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 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 2009.

Derivatives, historically, are recorded on the balance sheet at fair value and changes in the fair value of derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and, if it is, depending on the type of hedge transaction. The Company’s derivatives historically consist primarily of cash flow hedge transactions in which the Company is 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 are settled. The ineffective portion of the cash flow hedges was 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 are 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 (Prior authoritative literature: FASB Statement 133, Accounting for Derivative Instruments and Hedging Activities). 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 and unrealized gains or losses are recorded as gain (loss) on derivatives net, as an increase or decrease in revenues 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 (Prior authoritative literature, FASB Statement 144, Accounting for the Impairment and Disposal of Long-Lived Assets), 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 we use) 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, 2009, 2008, and 2007.

## 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 oil and 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:

<table><tr><td rowspan="2"></td><td colspan="4">Year Ended December 31, 2008</td></tr><tr><td>As Reported</td><td>Adjusted</td><td>Effect of Change</td><td></td></tr><tr><td>Deferred Tax Asset - Current</td><td>$ 1,433,000</td><td>$ 1,390,000</td><td>$ (43,000)</td><td></td></tr><tr><td>Oil and Gas Properties, Full Cost Method</td><td>55,680,567</td><td>47,260,838</td><td>(8,419,729)</td><td></td></tr><tr><td>Accumulated Depreciation and Depletion</td><td>856,010</td><td>748,421</td><td>(107,589)</td><td></td></tr><tr><td>Accrued Drilling Costs</td><td>8,419,729</td><td>-</td><td>(8,419,729)</td><td></td></tr><tr><td>Accumulated Deficit</td><td>$ (2,021,649)</td><td>$ (1,957,060)</td><td>$ 64,589</td><td></td></tr></table>

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

<table><tr><td rowspan="2"></td><td colspan="4">Year Ended December 31, 2008</td></tr><tr><td>As Reported</td><td>Adjusted</td><td>Effect of Change</td><td></td></tr><tr><td>Depletion Expense</td><td>$ 785,504</td><td>$ 677,915</td><td>$ (107,589)</td><td></td></tr><tr><td>Income Tax Provision (Benefit)</td><td>(873,000)</td><td>(830,000)</td><td>43,000</td><td></td></tr><tr><td>Net Income</td><td>$ 2,359,751</td><td>$ 2,424,340</td><td>$ 64,589</td><td></td></tr><tr><td>Earnings Per Share - Basic</td><td>$ 0.07</td><td>$ 0.08</td><td>$ 0.01</td><td></td></tr><tr><td>Earnings Per Share - Diluted</td><td>$ 0.07</td><td>$ 0.07</td><td>$ -</td><td></td></tr></table>

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

<table><tr><td rowspan="2"></td><td colspan="4">Year Ended December 31, 2008</td></tr><tr><td>As Reported</td><td>Adjusted</td><td>Effect of Change</td><td></td></tr><tr><td>Net Income</td><td>$ 2,359,751</td><td>$ 2,424,340</td><td>$ 64,589</td><td></td></tr><tr><td>Depletion of Oil and Gas Properties</td><td>785,504</td><td>677,915</td><td>(107,589)</td><td></td></tr><tr><td>Income Tax Benefit</td><td>(873,000)</td><td>(830,000)</td><td>43,000</td><td></td></tr><tr><td>Increase in Accrued Drilling Costs</td><td>8,419,729</td><td>-</td><td>(8,419,729)</td><td></td></tr><tr><td>Increase in Oil and Gas Properties</td><td>(46,416,886)</td><td>(37,997,157)</td><td>8,419,729</td><td></td></tr></table>

There was no effect on the Company’s Statement of Operations or Statement of Cash Flows for the year ended December 31, 2007. The Company did not commence production on its wells until 2008 and reported no Accrued Drilling Costs as of December 31, 2007.

New Accounting Pronouncements

In March 2008, the FSAB issued FASB ASC 815-10-15 (Prior authoritative literature, FASB Statement 161, Disclosures About Derivative Instruments and Hedging Activities). FASB ASC 815-10-15 is intended to improve financial reporting about derivative instruments and hedging activities by requiring enhanced disclosures to enable investors to better understand their effects on an entity's financial position, financial performance, and cash flows. FASB ASC 815-10-15 is effective for financial statements issued for fiscal years and interim periods.



beginning after November 15, 2008, with early application encouraged. Pursuant to the transition provisions of the Statement, the Company adopted FASB ASC 815-10-15 on January 1, 2009. The required disclosures are presented in Note 15 on a prospective basis. This Statement does not impact the financial results as it is disclosure-only in nature.

In April 2009, the FASB issued FASB ASC 270-10-05 (Prior authoritative literature: APB 28-1, Interim Disclosures About Fair Value of Financial Instruments). FASB ASC 270-10-05 amends FASB ASC 825-10-50 (Prior authoritative literature: FASB Statement 107, Disclosures About Fair Value of Financial Instruments) to require an entity to provide disclosures about fair value of financial instruments in interim financial information. FASB ASC 270-10-05 is to be applied prospectively and is effective for interim and annual periods ending after June 15, 2009 with early adoption permitted for periods ending after March 15, 2009. The required disclosures are presented in Note 13 on a prospective basis.

In February 2008, the FASB issued FASB ASC 820-10-65-1 (Prior authoritative literature: FSP FAS 157-2/Statement 157, Effective Date of FASB Statement No. 157.) FASB ASC 820-10-65-1 delayed the effective date for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). The adoption of the provisions of FASB ASC 820-10-65-1 related to nonfinancial assets and nonfinancial liabilities on January 1, 2009 did not have a material impact on the Financial Statements. See Note 13 for FASB ASC 820-10-65-1 disclosures.

In April 2009, the FASB issued FASB ASC 820-10-65-4 (Prior authoritative literature: FASB Statement 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly). FASB ASC 820-10-65-4 provides additional guidance in estimating fair value, when the volume and level of transaction activity for an asset or liability have significantly decreased in relation to normal market activity for the asset or liability. FASB ASC 820-10-65-4 also provides additional guidance on circumstances that may indicate a transaction is not orderly. FASB ASC 820-10-65-4 is effective for interim periods ending after June 15, 2009, and the Company has adopted its provisions during second quarter 2009. FASB ASC 820-10-65-4 did not have a significant impact on the Company's financial position, results of operations, cash flows, or disclosures.

In April 2009, the FASB issued FASB ASC 320-10-65 (Prior authoritative literature: FSP FAS 115-2/124-2, Recognition and Presentation of Other-Than-Temporary Impairments). The guidance applies to investments in debt securities for which other-than-temporary impairments may be recorded. If an entity's management asserts that it does not have the intent to sell a debt security and it is more likely than not that it will not have to sell the security before recovery of its cost basis, then an entity may separate other-than-temporary impairments into two components: 1) the amount related to credit losses (recorded in earnings), and 2) all other amounts (recorded in other comprehensive income). This ASC is to be applied prospectively and is effective for interim and annual periods ending after June 15, 2009 with early adoption permitted for periods ending after March 15, 2009. The adoption of the provisions of this ASC in the second quarter 2009 did not have a material impact on the Financial Statements.

In June 2009, the FASB issued FASB ASC 860-10-05 (Prior authoritative literature: FASB Statement 166, Accounting for Transfers of Financial Assets). FASB ASC 860-10-05 is effective for fiscal years beginning after November 15, 2009. The Company is currently assessing the impact of FASB ASC 860-10-05 on its financial position and results of operations.

In June 2009, the FASB issued FASB ASC 810-10-25 (Prior authoritative literature: FASB Statement 167-Amendment to FIN 46(R), Consolidation of Variable Entities). FASB ASC 810-10-25 eliminates the quantitative approach previously required for determining the primary beneficiary of a variable interest entity and requires a qualitative analysis to determine whether an enterprise's variable interest gives it a controlling financial interest in a variable interest entity. FASB ASC 810-10-25 contains certain guidance for determining whether an entity is a variable interest entity. This statement also requires ongoing reassessments of whether an enterprise is the primary beneficiary of a variable interest entity. FASB ASC 810-10-25 will be effective as of the beginning of the Company's 2010 fiscal year. The Company is currently evaluating the impact of the adoption of FASB ASC 810-10-25.



In June 2009, the FASB issued FASB ASC 105-10-65 (Prior authoritative literature: FASB Statement 168, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles). Under FASB ASC 105-10-65, the FASB Accounting Standards Codification  \( {}^{TM} \)  (the "Codification") becomes the exclusive source of authoritative U.S. generally accepted accounting principles ("U.S. GAAP") recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the Securities and Exchange Commission ("SEC") under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. The Codification will supersede all then-existing non-SEC accounting and reporting standards, with the exception of certain non-SEC accounting literature which will become nonauthoritative. FASB ASC 105-10-65 is effective for the Company's 2009 third fiscal quarter. The adoption of FASB ASC 105-10-65 did not have a material impact on the Company's Financial Statements. All references to U.S. GAAP provided in the notes to the Financial Statements have been updated to conform to the Codification.

In October 2009, the FASB issued ASU No. 200-13, Revenue Recognition – Multiple Deliverable Revenue Arrangements (“ASU 2009-13”). ASU 2009-13 updates the existing multiple-element revenue arrangements guidance currently included in FASB ASC 605-25. The revised guidance provides for two significant changes to the existing multiple-element revenue arrangements guidance. The first change relates to the determination of when the individual deliverables included in a multiple-element arrangement may be treated as separate units of accounting. This change will result in the requirement to separate more deliverables within an arrangement, ultimately leading to less revenue deferral. The second change modifies the manner in which the transaction consideration is allocated across the separately identified deliverables. Together, these changes will result in earlier recognition of revenue and related costs for multiple-element arrangements than under previous guidance. This guidance expands the disclosures required for multiple-element revenue arrangements. Effective for interim and annual reporting periods beginning after December 15, 2009. The Company is currently evaluating the potential impact, if any, of this guidance on its financial statements.

## 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 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). When securities are sold, their cost is determined based on the first-in first-out method. 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, 2009:

<table><tr><td></td><td colspan="2">Cost at December 31,</td><td rowspan="2">Unrealized (Loss)</td><td rowspan="2">Fair Market Value at December 31, 2009</td></tr><tr><td></td><td>2009</td><td>2009</td></tr><tr><td>Auction Rate Municipal Bonds</td><td>$ 1,750,000</td><td>$ (198,105)</td><td>$ 1,551,895</td><td></td></tr><tr><td>Auction Rate Preferred Stock</td><td>275,143</td><td>(8,682)</td><td>266,461</td><td></td></tr><tr><td>United States Treasuries</td><td>24,063,314</td><td>(978,194)</td><td>23,085,120</td><td></td></tr><tr><td>Total Short-Term Investments</td><td>$ 26,088,457</td><td>$ (1,184,981)</td><td>$ 24,903,476</td><td></td></tr></table>

For the year ended December 31, 2009 there were no realized gains or losses recognized on the sale of investments. In November 2008 we received, in a settlement agreement from UBS AG ("UBS"), rights which allow us to put back the auction rate securities at par value to UBS starting in June 2010. We expect to liquidate these investments at par no later than June 2010, in the meantime they continue to pay interest at various rates. Under the settlement agreement with UBS, we also have the ability to borrow up to 75% of the loan-to-market value of eligible auction rate securities on a no-net cost basis. As of December 31, 2009, we have borrowed $834,492 under this agreement, with an additional $684,258 of borrowings available under the agreement.

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 (Prior authoritative literature,



FASB Statement 115, 115-1, and 124-1, The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments). 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, 2009 and 2008, primarily based on estimated cash flows of the investments, the settlement agreement entered into with UBS, and the Company’s ability and intent to hold the investments until settlement.

## NOTE 4 PROPERTY AND EQUIPMENT

Property and equipment at December 31, 2009 and 2008, consisted of the following:

<table><tr><td rowspan="2"></td><td colspan="2">Year Ended December 31,</td></tr><tr><td>2009</td><td>2008 Adjusted</td></tr><tr><td>Oil and Gas Properties, Full Cost Method</td><td></td><td></td></tr><tr><td>Unevaluated Costs, Not Subject to Amortization or Ceiling Test</td><td>$ 53,862,529</td><td>$ 35,990,267</td></tr><tr><td>Evaluated Costs</td><td>42,939,097</td><td>11,270,571</td></tr><tr><td></td><td>96,801,626</td><td>47,260,838</td></tr><tr><td>Office Equipment, Furniture, Leasehold Improvements and Software</td><td>439,656</td><td>408,400</td></tr><tr><td></td><td>97,241,282</td><td>47,669,238</td></tr><tr><td>Less: Accumulated Depreciation, Depletion and Amortization</td><td></td><td></td></tr><tr><td>Property and Equipment</td><td>5,091,198</td><td>748,421</td></tr><tr><td>Total</td><td>$ 92,150,084</td><td>$ 46,920,817</td></tr></table>

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

<table><tr><td rowspan="2"></td><td colspan="2">Year Ended December 31,</td></tr><tr><td>2009</td><td>2008 Adjusted</td></tr><tr><td>Depletion of Costs for Evaluated Oil and Gas Properties</td><td>$ 4,250,983</td><td>$ 677,915</td></tr><tr><td>Depreciation of Office Equipment, Furniture, and Software</td><td>91,794</td><td>67,060</td></tr><tr><td>Total Depreciation, Depletion, and Amortization Expense</td><td>$ 4,342,777</td><td>$ 744,975</td></tr></table>

## NOTE 5 OIL AND GAS PROPERTIES

Acquisitions

Montana Acquisitions

In February 2007, the Company acquired leasehold interests in approximately 22,000 net mineral acres in Sheridan County, Montana. The Company paid a combination of cash and stock as consideration for such acquisition, including the issuance of an aggregate of 400,000 restricted shares of its common stock.

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



On November 13, 2009, we entered into a Letter of Intent with Slawson pursuant to which we agreed to acquire a twenty percent (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 we elect to participate, we will pay a participation interest share of all costs to drill, equip, complete, test and plug such well(s) on an at cost basis.

## 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 oil and 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 five percent (5.0%) interest of the undeveloped acreage, including approximately 60,000 net acres. The Company also acquired an additional nine percent (9%) interest in the existing well bores purchased from Windsor Bakken LLC, providing the Company an aggregate fourteen percent (14%) interest in the existing 59 gross Bakken and Three Forks well bores in North Dakota including approximately 1,200 barrels of 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 Exploration we acquired 24 high working interest sections comprising approximately 12,000 net acres located in western McKenzie and Williams Counties of North Dakota. We 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. We 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, we entered into an Exploration and Development Agreement with Area of Mutual Interest with Slawson pursuant to which we agreed to participate with a fifty percent (50%) working interest ownership, which equates to a thirty percent (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, we acquired an interest in 12,500 net acres in leases at $750 per net acre for a thirty percent (30%) interest and an aggregate sum of $2,812,500. We 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. We have the option to elect to participate or not participate as to each well drilled in the applicable project area. For each well in which we elect to participate, we will pay a participation interest share of all costs to drill, equip, complete, test and plug such wells on an at cost basis.

In addition to acquiring acreage through large block acquisitions, we have organically acquired approximately 4,000 net mineral acres in all of our key prospect areas in the form of both effective leases and top-leases. In this organic acquisition program we have spent an average of approximately $730 per net acre 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.



## New York Acquisition

In September 2007, the Company acquired leasehold interests in approximately 10,000 net mineral acres in the Appalachia Basin of New York. The Company paid a combination of cash and stock as consideration for such acquisition, including the issuance of an aggregate of 275,000 restricted shares of its common stock.

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.

## NOTE 6 PREFERRED AND COMMON STOCK

The Company has neither authorized nor issued any shares of preferred stock.

On May 3, 2007, the Company issued 100,000 shares of common stock to Insight Capital Consultants Corporation pursuant to a consulting agreement with them. The stock issued was valued at $475,000 and expensed to general and administrative expense. The shares were valued based on the market price of the Company’s stock on the date of issuance.

In September 2007, the Company completed a private placement of 4,545,455 shares of common stock to accredited investors at a subscription price of $3.30 per share for total gross proceeds of $15,000,002. In addition to common stock, investors purchasing shares in the private placement received a warrant to purchase common stock. For each share of common stock purchased in this transaction, the purchaser received the right to purchase one-half share of the Company's common stock at a price of $5.00 per share for a period of 18 months from the date of closing and the right to purchase one-half share of the Company's common stock at a price of $6.00 for a period of 48 months from the date of closing. The placement agents received consideration in cash and warrants of $1,191,000 which were netted against the proceeds of the offering through Additional Paid-In Capital. The total number of shares that are issuable upon exercise of warrants, including the placement agent's warrant is 4,818,183. All warrants issued as part of this private placement were exercised in 2008.

In November 2007, the Company issued 73,500 shares of common stock to various consultants pursuant to consulting agreements. The company also issued 75,000 shares of common stock to an employee pursuant to a written employment agreement. These 148,500 shares were valued at $769,230, the market value of the shares of common stock on the date of issuance, and expensed as general and administrative expenses. The shares were valued at the calculated fair value of the Company’s stock on the date of the issuance.

In December 2007, the Chief Executive Officer and Chief Financial Officer each exercised 500,000 stock options granted to them in 2006.

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 for three years over the 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, we 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, we 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 our 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.

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 employee 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 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 executive 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 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 Direct 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 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.

## Restricted Stock Awards

During the years ended December 31, 2009 and 2008, The Company issued 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, 2011. As of December 31, 2009, there was approximately $2.9 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:

<table><tr><td rowspan="2"></td><td colspan="2">Year Ended December 31, 2009</td><td colspan="2">Year Ended December 31, 2008</td></tr><tr><td>Number of Shares</td><td>Weighted-Average Price</td><td>Number of Shares</td><td>Weighted-Average Price</td></tr><tr><td>Restricted Stock Awards:</td><td></td><td></td><td></td><td></td></tr><tr><td>Restricted Shares Outstanding at the Beginning of the Year</td><td>20,000</td><td>$ 7.03</td><td>-</td><td>$ -</td></tr><tr><td>Shares Granted</td><td>361,330</td><td>$ 8.49</td><td>20,000</td><td>$ 7.03</td></tr><tr><td>Lapse of Restrictions</td><td>(56,000)</td><td>$ 4.91</td><td>-</td><td>$ -</td></tr><tr><td>Restricted Shares Outstanding at the End of the Year</td><td>325,330</td><td>$ 9.01</td><td>20,000</td><td>$ 7.03</td></tr></table>

## NOTE 7 RELATED PARTY TRANSACTIONS

The Company has purchased leasehold interests from South Fork Exploration, LLC (SFE). In 2009, the company paid a total of $501,603 related to a previously executed leasehold agreement. 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 MOP. MOP is controlled by Mr. Tom Ryan and Mr. Steven Reger, both are relatives of the Company’s CEO, Michael Reger.

The Company has also purchased leasehold interests from Gallatin Resources, LLC. Carter Stewart, one of the Company’s directors, owns a 25% interest in Gallatin Resources, LLC.

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 WARRANTIES

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. 260,000 options granted in 2007 have been exercised as of December 31, 2009.

The Company accounts for stock-based compensation under the provisions of FASB ASC 718-10-55 (Prior authoritative literature: FASB Statement 123(R), Share-Based Payment). This statement requires us to record an expense associated with the fair value of stock-based compensation. We use 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. The total fair value of the options are recognized as compensation over the vesting period. There have been no stock options granted in 2009 and 2008 under the 2006 Stock Option Plan, and all exercises of options during 2009 and 2008 related to 2007 grants.



On November 1, 2007, the Board of Directors granted 560,000 options to board members and one employee. The total fair value of the options was recognized as compensation in 2007 as the optionees were immediately vested. In computing the expected volatility, we used the combined historical volatility of the Company’s common stock for a one-month period and the blended historical volatility for two of our peer companies over a period of four years and eleven months. In computing the exercise price we used the average closing/last trade price of the Company’s common stock for the five highest volume trading days during the 30-day trading period ending on the last trading day preceding the date of the grants.

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

<table><tr><td></td><td>November 1, 2007</td></tr><tr><td>Risk free rates</td><td>4.36%</td></tr><tr><td>Dividend yield</td><td>0%</td></tr><tr><td>Expected volatility</td><td>56%</td></tr><tr><td>Weighted average expected stock option life</td><td>5 Years</td></tr></table>

The “fair market value” at the date of grant for stock options granted using the formula relied upon for calculating the exercise price is as follows:

<table><tr><td>Weighted average fair value per share</td><td>$ 2.72</td></tr><tr><td>Total options granted</td><td>560,000</td></tr><tr><td>Total weighted average fair value of options granted</td><td>$ 1,524,992</td></tr></table>

The following table presents the impact on our statement of operations of stock-based compensation expense related to options granted for the years ended December 31, 2009, 2008, and 2007:

<table><tr><td rowspan="2"></td><td colspan="4">Year Ended December 31,</td></tr><tr><td>2009</td><td>2008</td><td>2007</td><td></td></tr><tr><td>Expenses</td><td>$ -</td><td>$ -</td><td>$ 2,366,417</td><td></td></tr><tr><td>Option Stock-Based Compensation Expense Before Taxes</td><td>-</td><td>-</td><td>2,366,417</td><td></td></tr><tr><td>Income Tax Benefit</td><td>-</td><td>-</td><td>-</td><td></td></tr><tr><td>Option Stock-Based Compensation Expense After Taxes</td><td>$ -</td><td>$ -</td><td>$ 2,366,417</td><td></td></tr></table>



Changes in stock options for the years ended December 31, 2009, 2008, and 2007 were as follows:

<table><tr><td></td><td>Number of Shares</td><td>Weighted Average Exercise Price</td><td>Remaining Contractual Term (in Years)</td><td>Intrinsic Value</td></tr><tr><td>2007:</td><td></td><td></td><td></td><td></td></tr><tr><td>Beginning Balance</td><td>1,100,000</td><td>$ -</td><td>-</td><td>-</td></tr><tr><td>Granted</td><td>560,000</td><td>5.18</td><td>-</td><td>-</td></tr><tr><td>Exercised</td><td>1,000,000</td><td>1.05</td><td>-</td><td>-</td></tr><tr><td>Outstanding at December 31</td><td>660,000</td><td>4.55</td><td>9.7</td><td>1,581,200</td></tr><tr><td>Exercisable</td><td>660,000</td><td>4.55</td><td>9.7</td><td>1,583,200</td></tr><tr><td>Ending Vested</td><td>660,000</td><td>4.55</td><td></td><td>1,581,200</td></tr><tr><td>Weighted Average Fair Value of Options Granted During Year</td><td></td><td>$ 2.72</td><td></td><td></td></tr><tr><td>2008:</td><td></td><td></td><td></td><td></td></tr><tr><td>Beginning Balance</td><td>660,000</td><td>$ -</td><td>-</td><td>-</td></tr><tr><td>Granted</td><td>-</td><td>-</td><td>-</td><td>-</td></tr><tr><td>Exercised</td><td>260,000</td><td>3.59</td><td>-</td><td>-</td></tr><tr><td>Outstanding at December 31</td><td>400,000</td><td>5.18</td><td>8.8</td><td>-</td></tr><tr><td>Exercisable</td><td>400,000</td><td>5.18</td><td>8.8</td><td>-</td><td></td></tr><tr><td>Ending Vested</td><td>400,000</td><td>5.18</td><td>8.8</td><td>-</td></tr><tr><td>Weighted Average Fair Value of Options Granted During Year</td><td></td><td>$ -</td><td></td><td></td></tr><tr><td>2009:</td><td></td><td></td><td></td><td></td></tr><tr><td>Beginning Balance</td><td>400,000</td><td>$ -</td><td>-</td><td>-</td></tr><tr><td>Granted</td><td>-</td><td>-</td><td>-</td><td>-</td></tr><tr><td>Exercised</td><td>100,000</td><td>5.18</td><td>-</td><td>-</td></tr><tr><td>Outstanding at December 31</td><td>300,000</td><td>5.18</td><td>7.8</td><td>1,998,000</td></tr><tr><td>Exercisable</td><td>300,000</td><td>5.18</td><td>7.8</td><td>1,999,000</td></tr><tr><td>Ending Vested</td><td>300,000</td><td>5.18</td><td>7.8</td><td>1,998,000</td></tr><tr><td>Weighted Average Fair Value of Options Granted During Year</td><td></td><td>$ -</td><td></td><td></td></tr></table>

Currently Outstanding Options

●No options were forfeited or expired during the years ended December 31, 2009, 2008, and 2007.

●The company recorded compensation expense related to these options of $2,366,417 for the year ended December 31, 2007. 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, 2009, since the entire fair value compensation has been recognized based on the vesting period of the options during 2006 and 2007.

●There were no unvested options at December 31, 2009, 2008, and 2007.



## 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 Capital USA, Inc. (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 for three years over the term of the facility using the effective interest method. CIT can exercise the warrants at any time until the warrants expire in February 2012.

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

<table><tr><td></td><td>February 27, 2009</td></tr><tr><td>Risk free rates</td><td>1%</td></tr><tr><td>Dividend yield</td><td>0%</td></tr><tr><td>Expected volatility</td><td>96.43%</td></tr><tr><td>Weighted average expected warrant life</td><td>1.5 Years</td></tr></table>

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:

<table><tr><td>Weighted average fair value per share</td><td>$ .74</td></tr><tr><td>Total options granted</td><td>300,000</td></tr><tr><td>Total weighted average fair value of options granted</td><td>$ 221,153</td></tr></table>

In January 2009, the Company’s Board of Directors adopted the 2009 Equity Incentive Plan, pursuant to which we 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, 2009, we had issued 642,916 shares of common stock pursuant to our 2009 Equity Incentive Plan (See Note 6).

The table below reflects the status of warrants outstanding at December 31, 2009:

<table><tr><td>Issue Date</td><td>Common Shares</td><td>Exercise Price</td><td>Expiration Date</td></tr><tr><td>February 27, 2009</td><td>300,000</td><td>$ 5.00</td><td>February 27, 2012</td></tr></table>

At December 31, 2009 the per-share weighted average exercise price of outstanding warrants was $5.00 per share, and the weighted average remaining contractual life was 2.2 years. None of the warrants issued in 2009 were exercised and all of the warrants are exercisable at December 31, 2009.

## NOTE 9 REVOLVING CREDIT FACILITY

In February 2009, the Company completed the closing of a revolving credit facility with CIT Capital USA Inc. (“CIT”) that will provide up to a maximum principal amount of $25 million of working capital for exploration and production operations (the “Facility”). The borrowing base of funds available under the Facility will be redetermined 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 oil and gas properties. $11 million of financing was initially available under the Facility. In May 2009 CIT agreed to increase the current amount available under the Facility to $16 million in conjunction with the acquisition of certain assets of Windsor Bakken, LLC (see Note 5). An additional $9 million of financing could become available upon subsequent borrowing base redeterminations. The Facility terminates on February 27, 2012, with all outstanding borrowings due at that time. The Company had no borrowings under the facility at December 31, 2009.

The Company has the option to designate the reference rate of interest for each specific borrowing under the Facility as amounts are advanced. Borrowings based upon the London interbank offering rate (LIBOR) will be outstanding for a period of one, three or six months (as designated by us) and bear interest at a rate equal to 5.50% over the one-month, three-month or six-month LIBOR rate to be no less than 2.50%. Any borrowings not designated as being based upon LIBOR will have no specified term and generally will bear interest at a rate equal to 4.50% over the greater of (a) the current three-month LIBOR rate plus 1.0% or (b) the current prime rate as published by JP Morgan Chase Bank, N.A. The Company has the option to designate either pricing mechanism. Payments are due under the Facility in arrears, in the case of a loan based on LIBOR on the last day of the specified loan 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 Facility.



The applicable interest rate increases under the Facility and the lenders may accelerate payments under the Facility, or call all obligations due under certain circumstances, upon an event of default. The Facility references various events constituting a default on the Facility, including, but not limited to, failure to pay interest on any loan under the Facility, any material violation of any representation or warranty under the Credit Agreement in connection with the Facility, failure to observe or perform certain covenants, conditions or agreements under the Facility, 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 Facility. The Company was not in default on the Facility as of December 31, 2009, and is not expected to be in default in the future.

The Facility required that the Company enter into swap agreements with Macquarie Bank Limited (“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 other than basis differential swaps on volumes already hedged pursuant to other swap agreements), as of the date such swap agreement is executed, is not less than 50% of, nor exceeds 80% of, the reasonably anticipated projected production from the Company’s proved developed producing reserves. The hedged production is estimated to be equal to approximately 20% of 2009 total production and less than 10% of production volumes in 2010-12. See Note 15 for additional disclosure concerning these swap agreements.

All of the Company’s obligations under the Facility and the swap agreements with Macquarie are secured by a first priority security interest in any and all assets of the Company pursuant to the terms of a Guaranty and Collateral Agreement and perfected by a mortgage, notice of pledge and security and similar documents.

## 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 (Prior authoritative literature: FASB Statement 143, Accounting for Asset Retirement Obligations), 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, 2009 and 2008.

<table><tr><td rowspan="2"></td><td colspan="2">Year Ended December 31,</td></tr><tr><td>2009</td><td>2008</td></tr><tr><td>Beginning Asset Retirement Obligation</td><td>$ 61,437</td><td>$ -0-</td></tr><tr><td>Liabilities Incurred for New Wells Placed in Production</td><td>137,222</td><td>60,407</td></tr><tr><td>Accretion of Discount on Asset Retirement Obligations</td><td>8,082</td><td>1,030</td></tr><tr><td>Ending Asset Retirement Obligation</td><td>$ 206,741</td><td>61,437</td></tr></table>

## 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 (Prior authoritative literature: FASB Statement 109, Accounting for Income Taxes). 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, 2009, 2008, and 2007 consists of the following:

<table><tr><td rowspan="2"></td><td colspan="2">2009</td><td colspan="2">2008</td></tr><tr><td>2009</td><td>Adjusted</td><td>2007</td><td></td></tr><tr><td>Current Income Taxes</td><td>$ -</td><td>$ -</td><td>$ -</td><td>$ -</td></tr><tr><td>Deferred Income Taxes</td><td></td><td></td><td></td><td></td></tr><tr><td>Federal</td><td>1,215,000</td><td>(680,000)</td><td>-</td><td></td></tr><tr><td>State</td><td>251,000</td><td>(150,000)</td><td>-</td><td></td></tr><tr><td>Total Expense</td><td>$ 1,466,000</td><td>$ (830,000)</td><td>$ -</td><td></td></tr></table>

The following is a reconciliation of the reported amount of income tax expense (benefit) for the years ended December 31, 2009, 2008, and 2007 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:

<table><tr><td rowspan="2"></td><td colspan="3">2008</td></tr><tr><td>2009</td><td>Adjusted</td><td>2007</td></tr><tr><td>Income (Loss) Before Tau8xes and NOL</td><td>$ 4,264,952</td><td>$ 1,594,340</td><td>$ (4,305,293)</td></tr><tr><td>Federal Statutory Rate</td><td>X 34%</td><td>x 34%</td><td>x 34%</td></tr><tr><td>Taxes (Benefit) Computed at Federal Statutory Rates</td><td>1,450,000</td><td>540,000</td><td>(1,460,000)</td></tr><tr><td>State Taxes (Benefit), Net of Federal Taxes</td><td>295,000</td><td>110,000</td><td>-</td></tr><tr><td>Effects of:</td><td></td><td></td><td></td></tr><tr><td>Other</td><td>(279,000)</td><td>(7,659)</td><td>(12,341)</td></tr><tr><td>Change in Valuation</td><td>-</td><td>(1,472,341)</td><td>1,472,341</td></tr><tr><td>Reported Provision</td><td>$ 1,466,000</td><td>$ (830,000)</td><td>$ -</td></tr></table>

At December 31, 2009, 2008 and 2007, the Company has a net operating loss carryforward for Federal income tax purposes of $18,494,000, $9,348,000 and $1,950,000, respectively, which expires in varying amounts during the tax years 2027, 2028 and 2029.

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

<table><tr><td rowspan="3">Deferred Tax Assets</td><td colspan="2">Year Ended December 31,</td></tr><tr><td>2009</td><td>2008</td></tr><tr><td></td><td>Adjusted</td></tr><tr><td>Current:</td><td></td><td></td></tr><tr><td>Share Based Compensation (Options)</td><td>$ 774,000</td><td>$ 774,000</td></tr><tr><td>Share Based Compensation (Restricted Stock)</td><td>(91,000)</td><td>-</td></tr><tr><td>Unrealized Investment Losses</td><td>1,231,000</td><td>168,000</td></tr><tr><td>Accrued Payroll</td><td>288,000</td><td>520,000</td></tr><tr><td>Other</td><td>(145,000)</td><td>(72,000)</td></tr><tr><td>Current</td><td>2,057,000</td><td>1,390,000</td></tr><tr><td>Non-Current:</td><td></td><td></td></tr><tr><td>Net Operating Loss Carryforwards (NOLs)</td><td>7,583,000</td><td>3,588,000</td></tr><tr><td>Fixed Assets</td><td>(2,646,000)</td><td>(931,000)</td></tr><tr><td>Dry Well Write Off</td><td>(36,000)</td><td>(36,000)</td></tr><tr><td>Unrealized Investment Losses</td><td>395,000</td><td></td></tr><tr><td>Depletion</td><td>1,562,000</td><td>214,000</td></tr><tr><td>Intangible Drilling Costs</td><td>(7,955,000)</td><td>(2,962,000)</td></tr><tr><td>Sale of Land Lease Rights</td><td>117,000</td><td>117,000</td></tr><tr><td>Other</td><td>58,000</td><td>43,000</td></tr><tr><td>Non-Current</td><td>(922,000)</td><td>33,000</td></tr><tr><td>Total Deferred Tax Assets</td><td>1,135,000</td><td>1,423,000</td></tr><tr><td>Less: Valuation Allowance</td><td>-</td><td>-</td></tr><tr><td>Net Deferred Tax Asset</td><td>$ 1,135,000</td><td>$ 1,423,000</td></tr></table>

In June 2006, FASB issued FASB ASC 740-10-05-6 (Prior authoritative literature: FASB Statement 48, Accounting for Uncertainty in Income Taxes). We 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 our tax returns that do not meet these recognition and measurement standards.

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

Our policy is to recognize potential interest and penalties accrued related to unrecognized tax benefits within income tax expense. For the year ended



December 31, 2009, we did not recognize any interest or penalties in our Statement of Operations, nor did we have any interest or penalties accrued in our Balance Sheet at December 31, 2009 relating to unrecognized benefits.

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



## NOTE 12 OPERATING LEASES

## Vehicles

The Company leases vehicles under noncancelable operating leases. Total rent expense under the agreements was approximately $52,000, $31,000 and $22,000 for the years ended December 31, 2009, 2008, and 2007, respectively.

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

<table><tr><td>Year Ending December 31,</td><td>Amount</td></tr><tr><td>2010</td><td>$ 41,372</td></tr><tr><td>2011</td><td>$ 19,744</td></tr><tr><td>Total</td><td>$ 61,116</td></tr></table>

## 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 $142,000 and $114,000 for the years ended December 31, 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:

<table><tr><td>Year Ending December 31,</td><td>Amount</td></tr><tr><td>2010</td><td>$ 148,151</td></tr><tr><td>2011</td><td>154,087</td></tr><tr><td>2012</td><td>160,236</td></tr><tr><td>Total</td><td>$ 462,474</td></tr></table>

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 (Prior authoritative literature: FASB Statement 157, Fair Value Measurements) 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.

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, 2009 and 2008.

<table><tr><td rowspan="2"></td><td colspan="3">Fair Value Measurements at December 31, 2009 Using</td></tr><tr><td>Quoted Prices In Active Markets for Identical Assets (Level 1)</td><td>Significant Other Observable Inputs (Level 2)</td><td>Significant Unobservable Inputs (Level 3)</td></tr><tr><td>Current Derivative Liabilities</td><td>$ -</td><td>$ (1,320,679)</td><td>$ -</td></tr><tr><td>Non-Current Derivative Liabilities</td><td>-</td><td>(1,459,374)</td><td>-</td></tr></table>



<table><tr><td>Short-Term Investments (See Note 3)</td><td></td><td>23,085,120</td><td>-</td><td>1,818,356</td></tr><tr><td></td><td>Total</td><td>$ 23,085,120</td><td>$ (2,780,053)</td><td>$ 1,818,356</td></tr></table>



<table><tr><td rowspan="2"></td><td colspan="3">Fair Value Measurements at December 31, 2008</td></tr><tr><td colspan="2">Using</td><td></td></tr><tr><td></td><td>Quoted PricesIn ActiveMarkets forIdenticalAssets(Level 1)</td><td>SignificantOtherObservableInputs(Level 2)</td><td>SignificantUnobservableInputs(Level 3)</td></tr><tr><td>Long-Term Investments (See Note 3)</td><td>$ -</td><td>$ -</td><td>$ 2,416,369</td></tr><tr><td></td><td>Total</td><td>$ -</td><td>$ 2,416,369</td></tr></table>

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 (Prior authoritative literature: FASB Statement 157, Fair Value Measurements), the fair value of the Company's derivative financial instruments is determined based on the Company's valuation models that utilize market corroborated inputs. The fair value of all derivative contracts is reflected on the balance sheet. The current 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 (see Note 3) 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 predetermined “penalty” or “maximum” rates based on mathematical formulas in accordance with each security’s prospectus.

In February 2008, auctions began to fail for these securities and each auction since then has failed. Consequently, the investments are not currently liquid. In the event the Company needed to access these funds, they are not expected to be accessible until one of the following occurs: a successful auction occurs, the issuer redeems the issue, a buyer is found outside of the auction process or the underlying securities mature. In October 2008, the Company received an offer (the “Offer”) from UBS AG (“UBS”), one of its investment providers, to sell at par value auction-rate securities originally purchased from UBS ($2,025,143) at anytime during a two-year period beginning June 30, 2010. The Offer was non-transferable and expired on November 14, 2008. On October 28, 2008 the Company elected to participate in the Offer. The Company has classified auction rate securities as short-term assets on our balance sheet. In addition to the Offer, UBS is providing no net cost loans up to 75% of the loan-to-market value of eligible auction rate securities until June 30, 2010.

Typically, the fair value of ARS investments approximates par value due to the frequent resets through the auction process. While the Company continues to earn interest on its ARS investments at the contractual rate, these investments are not currently trading and therefore do not have a readily determinable market value. Accordingly, the estimated fair value of the ARS no longer approximates par value. At December 31, 2009, the Company valued the ARS investments based on Level 3 inputs. The Company utilized a discounted cash flow approach to arrive at this valuation. The assumptions used in preparing the discounted cash flow model include estimates of, based on data available as of December 31, 2009, interest rates, timing and amount of cash flows, credit and liquidity premiums, and expected holding periods of the ARS. These assumptions are volatile and subject to change as the underlying sources of these assumptions and market conditions change. Based on this Level 3 valuation, the Company valued the ARS investments at $1,818,356, which represents a decline in value of $206,787 from par.



Although there is uncertainty with regard to the short-term liquidity of these securities, the Company continues to believe that the carrying value represents the fair value of these marketable securities because of the overall quality of the underlying investments and the anticipated future market for such investments. In addition, the Company has the intent and ability to hold these securities until the earlier of: the market for auction rate securities stabilizes, the issuer refinances the underlying security, a buyer is found outside of the auction process at acceptable terms, the underlying securities have matured or the Company accepts the investment manager's offer to redeem the securities.

Based on the CIT financing, the expected positive operating cash flows, and the Company’s ability to obtain no net cost loans up to 75% of the loan-to-market value, as determined by UBS, on eligible auction rate securities, the Company does not anticipate the current inability to liquidate the auction rate securities to adversely affect the Company’s ability to conduct its business.

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):

<table><tr><td></td><td>Fair Value Measurements at Reporting Date Using Significant Unobservable Inputs (Level 3)</td></tr><tr><td></td><td>Level 3 Financial Assets</td></tr><tr><td>Balance at January 1, 2008</td><td>$ -</td></tr><tr><td>Purchases</td><td>3,800,524</td></tr><tr><td>Sales/Maturities</td><td>(975,000)</td></tr><tr><td>Realized Loss on Sales/Maturities</td><td>(381)</td></tr><tr><td>Unrealized Loss Included in Other Comprehensive Income (Loss)</td><td>(408,774)</td></tr><tr><td>Balance at December 31, 2008</td><td>$ 2,416,369</td></tr><tr><td>Sales</td><td>(800,000)</td></tr><tr><td>Unrealized Gain Included in Other Comprehensive Income (Loss)</td><td>201,987</td></tr><tr><td>Balance at December 31, 2009</td><td>$ 1,818,356</td></tr></table>

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.

<table><tr><td rowspan="2"></td><td rowspan="2">Description</td><td rowspan="2">December 31, 2009</td><td colspan="4">Fair Value Measurements at December 31, 2009 Using</td></tr><tr><td>Quoted Prices In Active Markets for Identical Assets (Level 1)</td><td>Significant Other Observable Inputs (Level 2)</td><td>Significant Unobservable Inputs (Level 3)</td><td></td></tr><tr><td>Other Non-current Liabilities</td><td></td><td>$ (206,741)</td><td>$ -</td><td>$ -</td><td>$ -</td><td>$ (206,741)</td></tr><tr><td></td><td>Total</td><td>$ (206,741)</td><td>$ -</td><td>$ -</td><td>$ -</td><td>$ (206,741)</td></tr></table>



<table><tr><td rowspan="2"></td><td rowspan="2">Description</td><td colspan="4">Fair Value Measurements at December 31, 2008 Using</td></tr><tr><td>December 31, 2008</td><td>Quoted Prices In Active Markets for Identical Assets (Level 1)</td><td>Significant Other Observable Inputs (Level 2)</td><td>Significant Unobservable Inputs (Level 3)</td></tr><tr><td>Other Non-current Liabilities</td><td></td><td>$ (61,437)</td><td>$ -</td><td>$ -</td><td>$ (61,437)</td></tr><tr><td></td><td>Total</td><td>$ (61,437)</td><td>$ -</td><td>$ -</td><td>$  (61,437)</td></tr></table>

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, 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.

The Company’s accounts receivable relate to 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. The Company’s accounts receivable at December 31, 2009 and 2008 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 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 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 oil and 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 derivatives 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 (Prior authoritative literature: FASB Statement 133, Accounting for Derivative Instruments and Hedging Activities). 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 and unrealized gains or losses are recorded as gain (loss) on derivatives, net, as an increase or decrease in revenue on the statement of operations rather than as a component of other comprehensive income or as other income (expense).



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 $2,416,639 as of December 31, 2009. The amount is in accumulated other comprehensive income in stockholders' equity and will be amortized into revenues as the original forecasted hedged oil production occurs in 2010 and 2011.

The Company realized a hedging loss of $624,541 and a hedging gain of $778,885 for the years ended December 31, 2009 and 2008, respectively.

The following table reflects open commodity derivative contracts as of December 31, 2009, the associated volumes and the corresponding weighted average NYMEX reference price.

<table><tr><td>Settlement Period</td><td>Oil (Barrels)</td><td>Fixed Price</td><td>Weighted Avg NYMEX Reference Price</td></tr><tr><td>Oil Swaps</td><td></td><td></td><td></td></tr><tr><td>01/01/10 - 02/29/12</td><td>63,000</td><td>51.25</td><td>83.99</td></tr><tr><td>01/01/10 - 12/31/11</td><td>36,000</td><td>66.15</td><td>84.20</td></tr><tr><td>01/01/10 - 12/31/11</td><td>132,000</td><td>82.60</td><td>83.68</td></tr><tr><td>01/01/10 - 12/31/11</td><td>54,000</td><td>84.25</td><td>83.56</td></tr></table>

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

<table><tr><td>Type of Contract</td><td>Balance Sheet Location</td><td>Estimated Fair Value</td></tr><tr><td>Derivatives Designated as Hedging Instruments</td><td></td><td></td></tr><tr><td>Derivative Liabilities:</td><td></td><td></td></tr><tr><td>Oil Contracts</td><td>Other Current Liabilities</td><td>$ 1,320,679</td></tr><tr><td>Oil Contracts</td><td>Other Non-Current Liabilities</td><td>1,459,374</td></tr><tr><td></td><td>Total Derivative Liabilities:</td><td>$ 2,780,053</td></tr></table>

## 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, 2009, 2008, and 2007:

<table><tr><td rowspan="2"></td><td colspan="3">2009</td><td colspan="3">2008</td><td colspan="3">2007</td></tr><tr><td>Net Income</td><td>Shares</td><td>Per Share</td><td>Net Income Adjusted</td><td>Shares</td><td>Per Share</td><td>Net Loss</td><td>Shares</td><td>Per Share</td></tr><tr><td>Basic EPS</td><td>$2,798,952</td><td>36,705,267</td><td>$ 0.08</td><td>$2,424,340</td><td>31,920,747</td><td>$ 0.08</td><td>$ (4,305,293)</td><td>23,667,119</td><td>$(0.18)</td></tr><tr><td>Dilutive effect of options</td><td>-</td><td>171,803</td><td>-</td><td>-</td><td>732,805</td><td>-</td><td>-</td><td>-</td><td>-</td></tr><tr><td>Diluted EPS</td><td>$2,798,952</td><td>36,877,070</td><td>$ 0.08</td><td>$2,424,340</td><td>32,653,552</td><td>$ 0.07</td><td>$ (4,305,293)</td><td>23,667,119</td><td>$(0.18)</td></tr></table>

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.

As of December 31, 2007, there were 600,000 potentially dilutive shares from stock options that became exercisable during 2007. In addition, there were 4,818,183 warrants that were issued and outstanding. These warrants were exercisable and represented potentially dilutive shares. As the Company had a loss for the year ended December 31, 2007 the potentially dilutive share were anti-dilutive and were not added into the earnings per share calculation.



## NOTE 17 COMPREHENSIVE INCOME

The Company follows the provisions of FASB ASC 220-10-55 (Prior authoritative literature: FASB Statement 130, Reporting Comprehensive Income) 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 stockholders of the Company.

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

<table><tr><td rowspan="2"></td><td colspan="3">Year Ended December 31, 2008</td></tr><tr><td>2009</td><td>Adjusted</td><td>2007</td></tr><tr><td>Net Income (Loss)</td><td>$ 2,798,952</td><td>$ 2,424,340</td><td>$ (4,305,293)</td></tr><tr><td>Unrealized losses on Short-term Investments (net of tax of $290,000 and $168,000 at December 31, 2009 and 2008)</td><td>(486,207)</td><td>(240,774)</td><td>-</td></tr><tr><td>Net unrealized losses on hedges (Net of tax of $933,000 at December 31, 2009)</td><td>(1,483,639)</td><td>-</td><td>-</td></tr><tr><td>Other Comprehensive income (loss) net</td><td>$ 829,106</td><td>$ 2,183,566</td><td>$ (4,305,293)</td></tr></table>

## 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 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 $66,400 to the 401(k) plan for the year ended December 31, 2009.

## NOTE 19 SUBSEQUENT EVENTS

In February 2010, the Company entered into a commodity swap contract. The oil swap contract is for 11,900 barrels of oil per month for the months of March 2010 through December 2010 and 4,583 barrels of oil per month in 2011. The price on the contract is fixed at $80.90 per barrel.

## 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 oil and gas properties relates to capitalized costs incurred in acquisition, exploration, and development activities. Results of operations do not include interest expense and general corporate amounts. The results of operations for the company's oil and gas production activities are provided in the company's related statements of operations.



## Costs Incurred and Capitalized Costs

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

<table><tr><td rowspan="2"></td><td colspan="3">Year Ended December 31,</td></tr><tr><td>2009</td><td>2008</td><td>2007</td></tr><tr><td>Costs Incurred for the Year:</td><td></td><td></td><td></td></tr><tr><td>Proved Property Acquisition</td><td>$ 30,800,883</td><td>$ 30,508,139</td><td>$ 3,231,694</td></tr><tr><td>Unproved Property Acquisition</td><td>-</td><td></td><td>4,169,773</td></tr><tr><td>Development</td><td>18,739,905</td><td>9,165,188</td><td>186,044</td></tr><tr><td>Total</td><td>$ 49,540,788</td><td>$ 39,673,327</td><td>$ 7,587,511</td></tr></table>

Excluded costs for unevaluated 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, 2009 by year incurred.

<table><tr><td rowspan="2"></td><td colspan="3">Year Ended December 31,</td></tr><tr><td>2009</td><td>2008</td><td>2007</td></tr><tr><td>Property Acquisition</td><td>$ 17,478,196</td><td>$ 29,080,499</td><td>$ 5,147,236</td></tr><tr><td>Drilling</td><td>394,066</td><td>1,762,532</td><td>-</td></tr><tr><td>Total</td><td>$ 17,872,262</td><td>$ 30,843,031</td><td>$ 5,147,236</td></tr></table>

## Oil and Natural Gas Reserves and Related Financial Data

Information with respect to the Company’s oil and 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 oil and gas reserves. The Company emphasizes that reserves are approximations and are expected to change as additional information becomes available. Reservoir engineering is a subjective process of estimating underground accumulations of oil and 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.



<table><tr><td></td><td>Natural Gas (MCF)</td><td>Oil (BLS)</td></tr><tr><td>Proved Developed and Undeveloped Reserves at December 31, 2007</td><td>-</td><td>-</td></tr><tr><td>Extensions, Discoveries and Other Additions</td><td>220,420</td><td>778,545</td></tr><tr><td>Production</td><td>(3,969)</td><td>(50,880)</td></tr><tr><td>Proved Developed and Undeveloped Reserves at December 31, 2008</td><td>216,451</td><td>727,665</td></tr><tr><td>Revisions of Previous Estimates</td><td>(27,820)</td><td>(93,819)</td></tr><tr><td>Extensions, Discoveries and Other Additions</td><td>1,619,597</td><td>5,456,261</td></tr><tr><td>Production</td><td>(47,305)</td><td>(274,528)</td></tr><tr><td>Proved Developed and Undeveloped Reserves at December 31, 2009</td><td>1,760,923</td><td>5,815,579</td></tr><tr><td>Proved Developed Reserves at December 31, 2008</td><td>216,451</td><td>727,665</td></tr><tr><td>Proved Developed Reserves at December 31, 2009</td><td>727,237</td><td>2,247,718</td></tr></table>

Proved reserves are estimated quantities of oil and 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.

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



<table><tr><td rowspan="2"></td><td colspan="2">Year Ended December 31,</td></tr><tr><td>2009</td><td>2008</td></tr><tr><td>Future Cash Inflows</td><td>$ 315,142,688</td><td>$ 29,342,354</td></tr><tr><td>Future Production Costs</td><td>(105,982,773)</td><td>(8,719,621)</td></tr><tr><td>Future Development Costs</td><td>(54,011,133)</td><td>(1,321,948)</td></tr><tr><td>Future Income Tax Expense</td><td>(43,761,765)</td><td>-</td></tr><tr><td>Future Net Cash Inflows</td><td>111,387,017</td><td>19,300,785</td></tr><tr><td></td><td></td><td></td></tr><tr><td>10% Annual Discount for Estimated Timing of Cash Flows</td><td>(43,580,456)</td><td>(7,514,731)</td></tr><tr><td>Standardized Measure of Discounted Future Net Cash Flows</td><td>$ 67,806,561</td><td>$ 11,786,054</td></tr></table>

The twelve month average prices for the year ended 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:

<table><tr><td></td><td>Natural Gas MCF</td><td>Oil Bbl</td></tr><tr><td>December 31, 2008 (Spot Price)</td><td>$ 5.80</td><td>$ 38.60</td></tr><tr><td>December 31, 2009 (Average)</td><td>$ 3.93</td><td>$ 53.00</td></tr></table>

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

<table><tr><td rowspan="2"></td><td colspan="2">Year Ended December 31,</td></tr><tr><td>2009</td><td>2008</td></tr><tr><td>Beginning of Period</td><td>$ 11,786,054</td><td>$ -</td></tr><tr><td>Sales of Oil and Natural Gas Produced, Net of Production Costs</td><td>(13,116,475)</td><td>(3,268,858)</td></tr><tr><td>Extensions and Discoveries</td><td>74,946,755</td><td>19,967,182</td></tr><tr><td>Previously Estimated Development Cost Incurred During the Period</td><td>1,321,948</td><td>-</td></tr><tr><td>Net Change of Prices and Production Costs</td><td>4,352,381</td><td>(3,660,754)</td></tr><tr><td>Change in Future Development Costs</td><td>-</td><td>(1,251,516)</td></tr><tr><td>Revisions of Quantity and Timing Estimates</td><td>(1,650,626)</td><td>-</td></tr><tr><td>Accretion of Discount</td><td>1,178,605</td><td>-</td></tr><tr><td>Change in Income Taxes</td><td>(20,005,322)</td><td>-</td></tr><tr><td>Purchase of Reserves in Place</td><td>9,579,951</td><td>-</td></tr><tr><td>Other</td><td>(586,710)</td><td>-</td></tr><tr><td>End of Period</td><td>$ 67,806,561</td><td>$ 11,786,054</td></tr></table>



## QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)

Quarterly data for the years ended December 31, 2009, 2008, and 2007 is as follows:

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

<table><tr><td rowspan="2"></td><td colspan="5">Quarter Ended</td></tr><tr><td>March 31, Adjusted**</td><td>June 30, Adjusted**</td><td>September 30, Adjusted**</td><td>December 31, Adjusted**</td><td></td></tr><tr><td>2008:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Revenue</td><td>$ 287,029</td><td>$ 764,528</td><td>$ 1,362,655</td><td>$ 1,907,667</td><td></td></tr><tr><td>Expenses</td><td>570,575</td><td>548,849</td><td>600,213</td><td>1,391,793</td><td></td></tr><tr><td>Income (Loss) from Operations</td><td>(283,546)</td><td>215,679</td><td>762,442</td><td>515,874</td><td></td></tr><tr><td>Other Income</td><td>96,269</td><td>95,424</td><td>155,121</td><td>37,077</td><td></td></tr><tr><td>Income Tax Provision (Benefit)</td><td>-</td><td>-</td><td>-</td><td>(830,000)</td><td></td></tr><tr><td>Net Income (Loss)</td><td>(187,277)</td><td>311,103</td><td>917,563</td><td>1,382,951</td><td></td></tr><tr><td>Net Income (Loss) Per Common Share - Basic and Diluted</td><td>(0.01)</td><td>0.01</td><td>0.03</td><td>0.03</td><td></td></tr></table>

<table><tr><td rowspan="2"></td><td colspan="5">Quarter Ended</td></tr><tr><td>March 31,</td><td>June 30,</td><td>September 30,</td><td>December 31,</td><td></td></tr><tr><td>2007:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Revenue</td><td>$ -</td><td>$ -</td><td>$ -</td><td>$ -</td><td>$ -</td></tr><tr><td>Expenses</td><td>297,719</td><td>894,720</td><td>*</td><td>309,487</td><td>3,011,263</td></tr><tr><td>Loss from Operations</td><td>(297,719)</td><td>(894,720)</td><td>*</td><td>(309,487)</td><td>(3,011,263)</td></tr><tr><td>Other Income</td><td>10,133</td><td>13,660</td><td></td><td>42,189</td><td>141,914</td></tr><tr><td>Net Loss</td><td>-</td><td>-</td><td>-</td><td>-</td><td>-</td></tr><tr><td>Net Loss Per Common Share - Basic and Diluted</td><td>(287,586)</td><td>(881,060)</td><td>*</td><td>(267,298)</td><td>(2,869,349)</td></tr><tr><td></td><td>(0.01)</td><td>(0.04)</td><td>*</td><td>(0.01)</td><td>(0.10)</td></tr></table>

* The second quarter 2007 financial statements were adjusted, from what was reported, as the company rescinded stock it had previously issued to Ibis Consulting Group, LLC.

** 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.



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# SUBORDINATED
PROMISSORY NOTE

$250,000.00

February 27, 2009

Wayzata, Minnesota

FOR VALUE RECEIVED, the undersigned, Northern Oil and Gas, Inc., a Nevada corporation (the "Company"), promises to pay to ___, a resident of the State of Minnesota, or his heirs, successors and/or assigns (the "Payee"), at such place as the Payee may designate from time to time, the principal sum of Two Hundred Fifty Thousand and No Cents ($250,000. \( ^{0} \) ) together with interest on the unpaid principal balance at the rate twelve percent (12.0%) per annum. Payee hereby acknowledges that this Subordinated Promissory Note (this "Note") supersedes any and all obligations of our company under that certain Promissory Note in the principal amount of $370,000. \( ^{0} \)  issued by the Company to the Payee on January 30, 2009.

Our company shall make payments to the Payee pursuant to this Note in arrears to the maximum extent permissible under that certain Credit Agreement dated as of February 27, 2009 among our company, as Borrower, CRT Capital USA Inc., as Administrative Agent and the Lenders Party thereto (as amended, restated, modified or supplemented, the "Credit Agreement"). Any unpaid principal amount and all accrued but unpaid interest on this Note shall be due and payable in full in a single lump sum on March 1, 2013. Our company reserves and shall have the right to repay at any time and from time to time the whole or any portion of the unpaid balance of this Note without premium or penalty, subject to the terms and conditions of the Credit Agreement. All payments shall be applied first to accrued but unpaid interest and then to any unpaid principal.

The unpaid balance of this Note shall, at the option of Payee and without presentment, demand, notice of dishonor or protest, all of which are hereby waived by Company, become immediately due and payable, in the case of any one or more of the following events of default occurring:

(a) Company shall become insolvent, unable to pay his debts as they mature, admit in writing his inability to pay his debts as they mature, become or be adjudicated bankrupt or shall voluntarily file a petition for bankruptcy;

(b) Company shall make a general assignment for the benefit of creditors; or

(c) Company shall apply for appointment of a receiver or a trustee for any substantial portion of his property or assets or shall permit the appointment of such receiver or trustee who is not discharged within a period of thirty (30) days after such appointment.

The indebtedness represented by this Note shall be unsecured and subordinate in right of payment and liquidation to the extent set forth in the Credit Agreement and any swap agreement entered into in connection with such Credit Agreement. This Note is non-negotiable, and the Payee may not transfer, assign, pledge or hypothecate this Note.

No delay or omission on the part of Payee in exercising any right hereunder shall operate as a waiver of such right or of any other remedy under this Note. A waiver on any one occasion shall not be



construed as a waiver of any such right or remedy on a future occasion. This Note is made with reference to and shall be construed in accordance with the laws of the State of Minnesota.

Northern Oil and Gas, Inc.

By Michael L. Reger

Its Chief Executive Officer

Acknowledged:

[NAME]



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## RESTRICTED STOCK AWARD AGREEMENT

This Restricted Stock Award Agreement (the “Agreement”) has been made as of ___, 20__ (the “Date of Award”), by Northern Oil and Gas, Inc. with its principal offices in Wayzata, Minnesota (the “Company”), to ___, who resides at ___(the “Grantee”).

## RECITALS

Under the Northern Oil and Gas, Inc. 2009 Equity Incentive Plan (the “Plan”), our company’s Compensation Committee of the Board of Directors (the “Committee”) has determined the form of this Agreement and selected the Grantee to receive this Restricted Stock Award and the shares of Northern Oil and Gas, Inc. Common Stock, par value $0.001 per share (“Common Stock”) that are subject hereto. The applicable terms of the Plan are incorporated in this Agreement by reference, including the definitions of terms contained in the Plan.

## RESTRICTED STOCK AWARD

In accordance with the terms of the Plan, our company has made this Restricted Stock Award effective as of the Date of Award first indicated above, and concurrently has issued to the Escrow Agent the shares of Common Stock upon the following terms and conditions:

## 1. Number of Shares

The number of shares of Common Stock issued or transferred under this Restricted Stock Award is ___.(___.

## 2. Rights of Grantee as Shareholder

The Grantee, as the owner of record of the shares of Common Stock issued pursuant to this Restricted Stock Award, is entitled to all the rights of a shareholder of our company, including the right to vote, the right to receive cash or stock dividends, and the right to receive shares in any recapitalization of our company. If the Grantee receives any additional shares by reason of being the holder of the shares of Common Stock issued or transferred under this Restricted Stock Award or of the additional shares previously distributed to the Grantee, all the additional shares shall be subject to the provisions of this Agreement.

## 3. Period of Restriction

The Period of Restriction under this Restricted Stock Award shall commence on the Date of Award and expire upon the earliest of (i) our company undergoes a Change of Control as defined in the Plan, (ii) the attainment of the following performance objectives:



, or (iii) if applicable, the vesting of shares of Common Stock issued under this Restricted Stock Award in equal installments of ___ shares each, in accordance with the following vesting schedule:

Vesting Date
(Expiration of Period of Restriction)

Shares Released from Restrictions

## 4. Conditions during Period of Restriction

During the Period of Restriction the following conditions must continue to be satisfied:

a. the employment of the Grantee with our company must not terminate for any reason; and

b. the Grantee must not, voluntarily or involuntarily, sell, assign, transfer, pledge, or otherwise dispose of the nonvested shares of Common Stock issued or transferred pursuant to this Restricted Stock Award.

## 5. Consequences of Failure to Satisfy Conditions

The following shall be the consequences of Grantee’s failure to satisfy the conditions in Sections 3 and 4 during the Period of Restriction.

a. If the conditions of Sections 3 and 4(a) are not satisfied, either by act of the Grantee or otherwise; (i) the Grantee will forfeit the nonvested shares of Common Stock issued or transferred pursuant to this Restricted Stock Award; (ii) the Grantee will assign and transfer the certificates evidencing ownership of such nonvested shares to our company, (iii) all interest of the Grantee in such nonvested shares shall terminate, and (iv) the Grantee shall cease to be a shareholder with respect to such nonvested shares.

b. Any attempted sale, assignment, transfer, pledge, or other disposition of the nonvested shares of Common Stock issued or transferred pursuant to this Restricted Stock Award in violation of the condition in Section 4(b), whether voluntary or involuntary, shall be ineffective and our company shall not be required to transfer the nonvested shares.

## 6. Lapse of Restrictions

At the end of the Period of Restriction, if the conditions specified in Sections 3 and 4(a) have been satisfied during the Period of Restriction, all restrictions shall terminate, and the Grantee shall be entitled to receive the certificates representing the shares out of escrow without the legend, provided that if the Grantee has attempted to violate the condition specified in Section 4(b), our company shall have no obligation to deliver unlegended certificates to anyone other than the Grantee. However, in the event of an attempted violation of the condition specified in Section 4(b), our company shall be entitled to withhold delivery of any of the certificates if, and for so long as, in the judgment of our company’s counsel, our company would incur a risk of liability to any party whom such shares were purported to be sold, transferred, pledged, or otherwise disposed.



## 7. Legend on Certificates

In the event a stock certificate is issued to evidence ownership of shares of Common Stock issued or transferred pursuant to this Restricted Stock Award, each certificate so issued during the Period of Restriction shall bear the following legend on the back side of the certificate:

These shares have been issued or transferred subject to a Restricted Stock Award Agreement and are subject to substantial restrictions, including but not limited to, a prohibition against transfer, either voluntarily or involuntarily, and a provision requiring transfer of these shares to Northern Oil and Gas, Inc. (the "Company") without any payment in the event of termination of the employment of the registered owner, all as more particularly set forth in a Restricted Stock Award Agreement, a copy of which is on file with our company.

In any event, our company or its transfer agent shall hold the shares of Common Stock issued or transferred pursuant to this Restricted Stock Award in escrow during the Period of Restriction.

## 8. Specific Performance of the Grantee’s Covenants

By accepting this Restricted Stock Award and the issuance and delivery of the shares of Common Stock pursuant to this Restricted Stock Award, the Grantee acknowledges that our company does not have an adequate remedy in damages for the breach by the Grantee of the conditions and covenants set forth in this Restricted Stock Award Agreement and agrees that our company is entitled to and may obtain an order or a decree of specific performance against the Grantee issued by any court having jurisdiction.

## 9. Employment with our company

Nothing in this Agreement or in the Plan shall confer upon the Grantee the right to continued employment with our company.

## 10. Section 83(b) Election

If the Grantee makes an election pursuant to § 83(b) of the Internal Revenue Code, the Grantee shall promptly file a copy of such election with our company.

## 11. Withholding Tax

Before a certificate for shares of Common Stock is issued or delivered pursuant to this Restricted Stock Award or if the Grantee makes the election permitted by § 83(b) of the Internal Revenue Code our company may, by notice to the Grantee, require that the Grantee pay to our company the amount of federal, state, or local taxes, if any, required by law to be withheld. Our company may satisfy the withholding obligation by withholding shares of Common Stock having a fair market value equal to the withholding tax; or by requiring the Grantee to pay to our company, in cash, an amount sufficient to cover our company’s withholding obligation.

[and/or]



If the Grantee makes an election pursuant to § 83(b) of the Internal Revenue Code, our company shall, within fifteen (15) days following the receipt by our company of a copy of such election, pay to the Grantee, or directly to the appropriate taxing authority, a cash bonus equal to the amount of state and federal income tax required to be paid by Grantee on Grantee’s receipt of the Restricted Stock Award, including tax incurred due to the payment of such cash bonus, as determined by our company in its sole discretion.

## 12. Notices of Payments

Any notice to be given by the Grantee under this Agreement shall be in writing and shall be deemed to have been given only upon receipt by the Secretary of our company at 315 Manitoba Avenue, Suite 200, Wayzata, Minnesota 55391, or at such address as may be communicated in writing to the Grantee from time to time. Any notice or communication by our company to the Grantee under this Agreement shall be in writing and shall be deemed to have been given if mailed or delivered to the Grantee at the address listed in the records of our company or at such address as specified in writing to our company by the Grantee.

## 13. Waiver

The waiver by our company of any provision of this Agreement shall not operate as, or be construed to be, a waiver of the same or any other provision of this Agreement at any subsequent time for any other purpose.

## 14. Termination or Modification of Restricted Stock Award

This Restricted Stock Award shall be irrevocable except that our company shall have the right to revoke this Agreement at any time during the Period of Restriction if it is contrary to law or modify this Restricted Stock Award to bring it into compliance with any valid and mandatory law or government regulation. In the event of revocation of this Agreement pursuant to the foregoing, our company may give notice to the Grantee that the nonvested shares of Common Stock are to be assigned, transferred, and delivered to our company as though the Grantee’s employment with our company terminated on the date of the notice.

## 15. Section Headings

The section headings in this Agreement are for convenience of reference only and shall not be deemed as part of, or germane to, the interpretation or construction of this Agreement.

## 16. Determination by Committee

Determinations by the Committee shall be final and conclusive with respect to the interpretation of the Plan and this Agreement.

## 17. Governing Law

The validity and construction of this Agreement shall be governed by the laws of the State of Nevada.

IN WITNESS WHEREOF, our company has caused this Agreement to be executed and granted in, to be effective as of ___, 20___.

Northern Oil and Gas, Inc.

By Michael L. Reger
Its Chief Executive Officer



## ACCEPTANCE OF RESTRICTED STOCK AWARD

The undersigned Grantee accepts this Restricted Stock Award and the ___ (___ ) shares of Common Stock issued or transferred under this Agreement and agrees to be bound by the provisions of this Agreement, including but not limited to the agreements and covenants of the Grantee expressed in § 4.

Dated this ___ day of ___, 20___.

Grantee



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# MANTYLA MCREYNOLDS LLC
178 South Rio Grande Street, Suite 200
Salt Lake City, Utah 84101
Telephone: 801.269.1818
Facsimile: 801.266.3481

The Board of Directors
Northern Oil and Gas, Inc.:

We hereby consent to the incorporation by reference in registration statements on Form S-8 (Nos. 333-148333 and 333-160602) and on Form S-3 (Nos. 333-158320 and 333-163779) of Northern Oil and Gas, Inc. our reports dated March 8, 2010, with respect to the balance sheets of Northern Oil and Gas, Inc., as of December 31, 2009 and 2008, and the related statements of operations, stockholders' equity, and cash flows for each of the years in the three-year period ended December 31, 2009 and the effectiveness of internal control over financial reporting as of December 31, 2009, which reports appear in the December 31, 2009 annual report on Form 10-K of Northern Oil and Gas, Inc.

/s/ Mantyla McReynolds LLC

Salt Lake City, Utah
March 8, 2010



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# CONSENT OF RYDER SCOTT COMPANY, L.P.

Northern Oil and Gas, Inc.
315 Manitoba Avenue – Suite 200
Wayzata, Minnesota 55391

Gentlemen:

The undersigned hereby consents to the references to our firm in the form and context in which they appear in the Annual Report on Form 10-K of Northern Oil and Gas, Inc. for the year ended December 31, 2009 (the "Annual Report"). We hereby further consent to the inclusion in the Annual Report of estimates of oil and gas reserves contained in our reports "Northern Oil and Gas, Inc. – Estimated Future Reserves and Income Attributable to Certain Leasehold Interests – SEC Parameters – As of December 31, 2009" and "Northern Oil and Gas, Inc. – Estimated Future Reserves and Income Attributable to Certain Leasehold Interests – $80 Oil – Sensitivity Case – As of December 31, 2009," and to the inclusion of our report dated February 23, 2010 as an exhibit to the Annual Report. We further consent to the incorporation by reference thereof into Northern Oil and Gas, Inc.'s Registration Statements on Form S-8 (Registration Nos. 333-148333 and 333-160602) and on Form S-3 (Registration Nos. 333-158320 and 333-163779).

RYDER SCOTT COMPANY, L.P.

/s/ Ryder Scott Company, L.P.

Denver, Colorado

March 8, 2010



# CERTIFICATION

I, Michael L. Reger, certify that:

1. I have reviewed this annual report on Form 10-K of Northern Oil and Gas, Inc. for the year ended December 31, 2009;

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

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

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

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

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

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

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

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

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

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

Dated: March 8, 2010

By: /s/Michael L. Reger
Michael L. Reger
Chief Executive Officer



## CERTIFICATION

I, Ryan R. Gilbertson, certify that:

1. I have reviewed this annual report on Form 10-K of Northern Oil and Gas, Inc. for the year ended December 31, 2009;

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

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

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

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

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

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

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

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

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

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

Dated: March 8, 2010

By: /s/ Ryan R. Gilbertson
Ryan R. Gilbertson
Chief Financial Officer



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# CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Northern Oil and Gas, Inc., on Form 10-K for the period ended December 31, 2009, as filed with the United States Securities and Exchange Commission on the date hereof, (the "Report"), each of the undersigned officers of our company hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of his knowledge:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of our company.

Date: March 8, 2010

By:

/s/ Michael L. Reger

Michael L. Reger

Chief Executive Officer and Director

Date: March 8, 2010

By:

/s/ Ryan R. Gilbertson

Ryan R. Gilbertson

Chief Financial Officer and Director

A signed original of this written statement required by Section 906 of the Sarbanes-Oxley Act of 2002 has been provided to our company and will be retained by our company and furnished to the Securities and Exchange Commission or its staff upon request.



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# REPORT OF RYDER SCOTT COMPANY, L.P.

Northern Oil and Gas, Inc.
315 Manitoba Avenue – Suite 200
Wayzata, Minnesota 55391

Gentlemen:

At your request, we have prepared an estimate of the reserves, future production, and income attributable to certain leasehold interests of Northern Oil and Gas, Inc. as of December 31, 2009. The subject properties are located in the States of Montana and North Dakota. The reserves and income data were estimated based on the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). The proved net reserves attributable to the properties that we evaluated account for 100 percent to the total proved net liquid hydrocarbon and total net gas reserves. The results of our third party study, completed on February 23, 2010, are presented herein.

The estimated reserves and future net income amounts presented in this report, as of December 31, 2009 are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized below.

## SEC PARAMETERS
Estimated Net Reserves and Income Data*
Certain Leasehold Interests of
Northern Oil and Gas, Inc.
As of December 31, 2009

<table><tr><td rowspan="2"></td><td colspan="4">Proved</td></tr><tr><td colspan="2">Developed</td><td rowspan="2">Undeveloped</td><td rowspan="2">Total Proved*</td></tr><tr><td>Net Remaining Reserves</td><td>Producing</td><td>Non-Producing</td></tr><tr><td>Oil/Condensate - Barrels</td><td>1,647,031</td><td>600,687</td><td>3,567,862</td><td>5,815,579</td></tr><tr><td>Plant Products - Barrels</td><td>0</td><td>0</td><td>0</td><td>0</td></tr><tr><td>Gas - MMCF</td><td>513</td><td>214</td><td>1,034</td><td>1,761</td></tr><tr><td>Income Data M$</td><td></td><td></td><td></td><td></td></tr><tr><td>Future Gross Revenue</td><td>$79,213</td><td>$28,985</td><td>$171,258</td><td>$279,456</td></tr><tr><td>Deductions</td><td>22,341</td><td>9,858</td><td>92,108</td><td>124,308</td></tr><tr><td>Future Net Income (FNI)</td><td>$56,872</td><td>$19,126</td><td>$79,150</td><td>$155,149</td></tr><tr><td>Discounted FNI @ 10%</td><td>37,785</td><td>$12,795</td><td>$37,233</td><td>$87,812</td></tr></table>

 \( ^{*} \) From Landmark Graphics Corporation’s “ARIES”.

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are sales gas expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. The various producing status categories are defined under the tab "Reserve Definitions" in this report.



The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package Aries for Windows, a copyrighted program of Landmark Graphics. The program was used solely at the request of Northern Oil and Gas, Inc. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The future gross revenue is after the deduction of production taxes. The deductions are comprised of the normal direct costs of operating the wells, ad valorem taxes, recompletion costs and development costs. The future net income is before the deduction of state and federal income taxes and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income. Liquid hydrocarbon reserves account for approximately 98 percent and gas reserves account for 2 percent of total future gross revenue from proved reserves.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.

Discounted Future Net Income

As of December 31, 2009

<table><tr><td>Discount Rate Percent</td><td>Total Proved M\(</td></tr><tr><td>5</td><td>$112,930</td></tr><tr><td>15</td><td>$71,353</td></tr><tr><td>20</td><td>$59,793</td></tr><tr><td>25</td><td>$51,253</td></tr></table>

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

## Reserves Included in This Report

The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission's Regulation S-X Part 210.4-10 (a) as clarified by subsequent Commission Staff Accounting Bulletins. The definitions of proved reserves are included under the tab “Petroleum Reserves Definitions” in this report. The reserves and income quantities attributable to the different reserve classifications that are included herein have not been adjusted to reflect the varying degrees of risk associated with them and thus are not comparable.

## Estimates of Reserves

The reserves for the properties included herein were estimated by performance methods or analogy. In general, reserves attributable to producing wells and/or reservoirs were estimated by performance methods such as decline curve analysis which utilized extrapolations of historical production data. Reserves attributable to non-producing and undeveloped reserves included herein were estimated by analogy.

To estimate economically recoverable oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under 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 productivity from a reservoir is to be determined as of the effective date of the report. Northern Oil and Gas, Inc. has informed us that they have furnished us all of the accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future production and income, we have relied upon data furnished by Northern Oil and Gas, Inc. with respect to property interests owned, 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, product prices based on the SEC regulations, geological maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data supplied by Northern Oil and Gas, Inc.



The reserves included in this report are estimates only and should not be construed as being exact quantities. They may or may not be actually recovered, and if recovered, the revenues therefrom and the actual costs related thereto could be more or less than the estimated amounts. Moreover, estimates of reserves may increase or decrease as a result of future operations.

## Future Production Rates

Initial production rates are based on the current producing rates for those wells now on production. Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations which are not currently producing. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Northern Oil and Gas, Inc.

The future production rates from wells now on production may be more or less than estimated because of changes in market demand or allowables set by regulatory bodies. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates.

## Hydrocarbon Prices

The hydrocarbon prices used herein are based on the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.

## Costs

Operating costs for the leases and wells in this report were furnished by Northern Oil and Gas, Inc. and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. When applicable for operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs. The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by Northern Oil and Gas, Inc. and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage was significant. The estimates of the zero net abandonment costs furnished by Northern Oil and Gas, Inc. were accepted without independent verification.

Because of the direct relationship between volumes of proved undeveloped reserves and development plans, we include in the proved undeveloped category only reserves assigned to undeveloped locations that we have been assured will definitely be drilled. Northern Oil and Gas, Inc. has assured us of their intent and ability to proceed with the development activities included in this report, and that they are not aware of any legal, regulatory or political obstacles that would significantly alter their plans.

Current costs used by Northern Oil and Gas, Inc. were held constant throughout the life of the properties.

## Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy years. Ryder Scott is employee owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any publicly traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Ryder Scott requires that staff engineers and geoscientists have received professional accreditation, and are maintaining in good standing, a registered or certified professional engineer's license or a registered or certified professional geoscientist's license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization prior to becoming an officer of the Company.

We are independent petroleum engineers with respect to Northern Oil and Gas, Inc.. Neither we nor any of any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The professional qualifications of the undersigned, the technical person primarily responsible for reviewing and approving the reserves information discussed in this report, are included as an attachment to this letter.

## Terms of Usage

This report was prepared for the exclusive use and sole benefit of Northern Oil and Gas, Inc. and may not be put to other use without our prior written consent for such use. The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please



contact us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, L.P.
TBPF Firm Registration No. F-1580

/s/ Richard J. Marshall

Richard J. Marshall P.E.
Vice President

Approved:

/s/ James L. Baird

James L. Baird, P.E.

Senior Vice President



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