- Prospectus filed pursuant to Rule 424(b)(3) (424B3)

Filed Pursuant to Rule 424b3
Registration No. 333-181739

PROSPECTUS

ARÊTE INDUSTRIES, INC.

1,583,333 Shares of Common Stock

This prospectus relates to the resale of up to 1,583,333 shares of our common stock that may be offered and sold, from time to time, by the selling shareholders identified in this prospectus for their own account, consisting of 1,583,333 shares of common stock issuable upon conversion of 522.5 shares of 15% Series A1 convertible preferred stock, which we refer to as convertible preferred stock, which we sold in a private placement.

All of the shares of common stock are being offered by the selling shareholders named in this prospectus, or their assigns or successors in interest. The selling shareholders will receive all of the proceeds from the sale of the securities being offered by this prospectus.

The selling shareholders may sell the common stock being offered by them from time to time in the over the counter market, on one or more stock exchanges, in market transactions, in negotiated transactions or otherwise, and at prices and at terms that will be determined by the then-prevailing market price for the securities or at negotiated prices directly or through broker-dealers, who may act as agent or as principal, or by a combination of such methods of sale. For additional information on the methods of sale, you should refer to the section entitled “Plan of Distribution” on page 43 of this prospectus.

Our common stock currently trades over the counter and is quoted on the OTCQB tier of the OTC Markets under the symbol “ARET.OTCQB” On October 16, 2012, the last sale of our common stock was $.33 per share.

These securities are speculative and involve a high degree of risk. For a description of certain important factors that should be considered by prospective investors, see “ Risk Factors ” beginning on page 5 of this prospectus.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of our common stock or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

The date of this prospectus is October 31, 2012

TABLE OF CONTENTS


Prospectus Summary					4
Risk Factors					5
Use of Proceeds					14
Business and Properties					15
Market For Common Equity and Related Shareholder Information					21
Management’s Discussion and Analysis of Financial Condition and Results of Operations					23
Management					34
Certain Relationships and Related Transactions					38
Security Ownership of Certain Beneficial Owners and Management					40
Selling Shareholders					42
Plan Of Distribution					43
Description of Capital Stock					45
Shares Eligible For Future Sale					48
Disclosure of Commission Position on Indemnification for Securities Act Liabilities					49
Where You Can Find More Information					49
Legal Matters					49
Experts					50
Certain Definitions					51
Index To Financial Statements					F-1

About this Prospectus

This prospectus is part of a registration statement that we filed with the Securities and Exchange Commission, or the SEC, utilizing a “shelf” registration process or continuous offering process. Under this shelf registration process, the selling shareholders may, from time to time, sell the common stock described in this prospectus in one or more offerings. This prospectus provides you with a description of the common stock that may be offered by the selling shareholders. Each time a selling shareholder sells the common stock described in this prospectus, the selling shareholder is required to provide you with this prospectus and, in certain cases, a prospectus supplement containing specific information about the selling shareholder and the terms of the offering. Any prospectus supplement may add, update, or change information in this prospectus. If there is any inconsistency between the information in this prospectus and any prospectus supplement, you should rely on the information in that prospectus supplement. Please read “Where You Can Find More Information.” You are urged to read this prospectus carefully, including the “Risk Factors” in their entirety before investing in our common stock.

Additional Information

This prospectus contains descriptions of certain contracts, agreements or other documents affecting our business. These descriptions are not necessarily complete. For the complete text of these documents, you can refer to the exhibits filed with the registration statement of which this prospectus is a part or incorporated into the registration statement. See, “Where You Can Find More Information” beginning on page 49.

You should rely only on the information contained in this prospectus, or to which we have referred you. We have not authorized anyone to provide you with information other than as contained or referred to in this prospectus. This document may only be used where it is legal to sell these securities. The information in this document may only be accurate as of the date of this document.

Cautionary Statement Regarding Forward-Looking Statements

Certain statements contained in this prospectus (and other documents to which it refers) are not statements of historical fact and constitute forward-looking statements within the meaning of the various provisions of the Securities Act of 1933, as amended, which we refer to as the Securities Act, and the Securities Exchange Act of 1934, as amended, which we refer to as the Exchange Act, including, without limitation, the statements specifically identified as forward-looking statements within this prospectus. Many of these statements contain risk factors as well. In addition, certain statements in our future filings with the SEC, in press releases, and in oral and written statements made by or with our approval which are not statements of historical fact constitute forward-looking statements within the meaning of the Securities Act and the Exchange Act. Examples of forward-looking statements, include, but are not limited to: (i) projections of capital availability, terms, expenditures, revenues, income or loss, earnings or loss per share, the payment or non-payment of dividends on our common stock and on our convertible preferred stock, capital structure, and other financial items, (ii) statements of our plans and objectives or our management or board of directors including those relating to planned development of our oil and gas properties, (iii) statements of future economic performance and (iv) statements of assumptions underlying such statements. Words such as “believes”, “anticipates”, “expects”, “intends”, “targeted”, “may”, “will” and similar expressions are intended to identify forward-looking statements but are not the exclusive means of identifying such statements. Important factors that could cause actual results to differ materially from the forward looking statements include, but are not limited to:

•

changes in production volumes, worldwide demand and commodity prices for oil and natural gas;

•

changes in estimates of proved reserves;

•

declines in the values of our oil and natural gas properties resulting in impairments;

•

the timing and extent of our success in discovering, acquiring, developing and producing oil and natural gas reserves;

•

our ability to acquire leases, drilling rigs, supplies and services at reasonable prices;

•

risks incident to the drilling and operation of oil and natural gas wells;

•

future production and development costs;

•

the availability of sufficient pipeline and other transportation facilities to carry our production and the impact of these facilities on price;

•

the effect of existing and future laws, governmental regulations and the political and economic climate of the United States of America;

•

changes in environmental laws and the regulation and enforcement related to those laws;

•

the identification of and severity of environmental events and governmental responses to the events;

•

the effect of oil and natural gas derivatives activities; and

•

conditions in the capital markets.

Such forward-looking statements speak only as of the date on which such statements are made, and we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made to reflect the occurrence of unanticipated events.

PROSPECTUS SUMMARY

The following summary highlights information contained elsewhere in this prospectus. It does not contain all of the information you should consider before investing in our securities. You should read the entire prospectus carefully, including “Risk Factors” and our consolidated financial statements.

As used in this prospectus, unless the context requires otherwise, the terms “Company,” “we,” “our” and “us” refer to Arête Industries Inc.

Our Company

Arête Industries, Inc., a Colorado corporation, is an independent oil and gas company engaged in the acquisition and development of oil and natural gas reserves through a program which includes purchases of reserves, re-engineering, development and exploration activities primarily focused in Wyoming, Kansas, Colorado and Montana. Our corporate headquarters is located in Westminster, Colorado.

We were incorporated in the state of Colorado in 1987. Our corporate office is located at 7260 Osceola Street, Westminster, Colorado 80030, and our telephone number is 303-427-8688. Our Website can be found at www.arêteindustries.com . The information available on or through our website is not part of this prospectus.

The Offering

In May 2011 we entered into a purchase and sale agreement which was subsequently amended, for the purchase of certain oil and gas properties in Colorado, Kansas, Wyoming, and Montana. The final purchase price for the acquisition was $11,000,000. The purchase was part of our strategy to enter the oil and natural gas exploration and production business. We completed the property purchase under the purchase and sale agreement, as amended, in the third quarter of 2011. The payment of the final installment payment was financed through the completion of a private placement of 522.5 shares of our convertible preferred stock. Shares of our convertible preferred stock are convertible into shares of our common stock at a conversion price of $3.30 per share, subject to customary anti-dilution adjustments, including in connection with stock dividends and distributions, stock splits, subdivisions and combinations. Under the terms of the sale in the private placement, we are required to register with the SEC the resale of the common stock issuable upon conversion of the convertible preferred stock. This prospectus covers the resale of 1,583,333 shares of our common stock by selling shareholders in market or negotiated transactions. None of the shares are currently outstanding but are issuable upon conversion of our convertible preferred stock held by the selling shareholders. The following table summarizes certain information concerning this offering.


Common stock outstanding before the offering		7,979,803 shares (1)
Common stock issuable upon conversion of convertible preferred stock		1,583,333 shares
Common stock offered by the selling shareholders		1,583,333 shares
Common stock outstanding after the offering		9,563,136 shares (2)
Use of proceeds		$ — (3)
Stock symbol		“ARET.OTCQB” on the OTC Market

(1)	Excludes shares which may be issued upon exercise of the outstanding shares of convertible preferred stock at the existing conversion value.

(2)	Assumes conversion of all of the outstanding shares of the convertible preferred stock, of which there is no assurance.

(3)	We will receive no proceeds from the sale of the shares by the selling shareholders.

Risk Factors

An investment in our common stock is subject to a number of risks. Risk factors relating to our company include: a shortage of working capital; we need to obtain financing to carry out our business plan; intense competition in our industry; a history of operating losses; limited operations until recently; and dependence on key officers. Risk factors relating to our common stock include the volatility of our stock price, our limited trading market and lack of dividends. See, “Risk Factors” in the next section for a full discussion of these and other risks.

Access to Information

Our website address is www.arêteindustries.com We make available, free of charge, by clicking on the Investor Relations tab at the top of our homepage and then selecting “SEC Filings” in the drop down menu section of our website, our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and all amendments to those reports, as soon as reasonably practicable after these reports are electronically filed with or furnished to the SEC. We also make available through our website other reports electronically filed with the SEC under the Exchange Act, including our proxy statements. Information contained in our website is not part of this prospectus.

RISK FACTORS

An investment in our common stock involves a high degree of risk. You should consider carefully the following risks, along with all of the other information included in this prospectus, before deciding to buy our common stock. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may also impair our business operations. If we are unable to prevent events that have a negative effect from occurring, then our business may suffer. Some of the information in this prospectus contains forward-looking statements that involve substantial risks and uncertainties. These statements can be identified by forward-looking words such as “may,” “will,” “expect,” “anticipate,” “believe,” “intend,” “estimate,” and “continue” or other similar words. Statements that contain these words should be carefully read for the following reasons:

•

The statements may disclose our future expectations;

•

The statements may contain projections of our future earnings or our future financial condition; and

•

The statements may state other “forward-looking” information.

Risks Related to Our Business and Industry

We have a significant working capital deficit.

At June 30, 2012, we had a working capital deficit of $1,454,805. Cash flow from operations in 2012 has allowed us to maintain our working capital deficit without any material adverse consequences, but we cannot make any assurances that we will be able to reduce this working capital deficit or that it will not require significant drastic measures be taken to eliminate the deficit, which would in all likelihood materially and adversely affect our planned operations and results of operations.

We will require additional capital in seeking to execute our business plan, which may not be available or may only be available on unfavorable terms.

Our future capital requirements depend on many factors, including development and acquisition opportunities, the availability of debt financing and the cash flow from our operations. To the extent that the funds available are insufficient to meet future capital requirements, we will likely need to reduce our development activity. Any equity or debt financing, if available at all, may be on terms that are not favorable to us. If we cannot obtain adequate capital on favorable terms or at all, our business, operating results and financial condition will likely be adversely affected.

We do not have any employees and we depend on our chief executive officer for a significant majority of our management decisions, operations and industry contacts.

Due to our limited operations, we do not have any employees, and our executive officers are retained as independent contractors on a part-time basis. We are heavily dependent upon the efforts of our Chief Executive Officer, Donald W. Prosser, who essentially operates our company. We do not have an employment agreement with him nor do we have any key man insurance on his life. As we currently do not have a successor to Mr. Prosser, the loss of his services would likely have a material adverse impact on our business.

Our future performance is difficult to evaluate because we have a limited operating history.

Our operations in the natural resources industry commenced with our acquisition of a gas gathering pipeline as of September 2006. In the third quarter of 2011, we purchased various oil and gas producing properties for a base purchase price of $11,000,000. Prior to our third quarter of 2011 asset acquisition, our revenues were minimal and we incurred significant losses. As of June 30, 2012, our accumulated deficit was nearly $15.4 million. With respect to our acquisition of the oil and gas producing properties in 2011, we have little historical financial and operating information available to assist you in evaluating an investment in our common stock.

Oil and gas prices must remain at sufficient levels in order for us to operate profitably.

We expect to focus on acquiring oil and gas properties that we believe offer profit potential from overlooked and by-passed reserves of oil and natural gas, which will include shut-in wells, in-field development, stripper wells, re-completion and re-working projects. Because production is generally on a decline on these mature properties while operating expenses can be high, declines in oil and gas prices will likely have a greater negative impact on our operations compared to oil and gas companies that focus on newer developed properties.

We may expend substantial funds in acquiring and redeveloping properties which are later determined to not be economically viable.

The search for new oil and gas reserves, development wells or secondary recovery frequently result in unprofitable efforts, not only from dry holes, but also from wells which, though productive, will not produce oil or gas in sufficient quantities to return a profit on the costs incurred. There is no assurance that any production will be obtained from any of the acreage to be acquired by us, nor are there any assurances that if such production is obtained, it will be profitable. We may expend substantial funds in acquiring and redeveloping properties which are later determined not to be economically viable. All funds so expended may be a total loss to us and which could result in possibly significant impairments in our oil and gas asset base. In such event, our profitability and operations may be materially adversely affected.

The domestic oil and gas exploration and production industry is faced with shortages of personnel and equipment, and such shortages may adversely affect our operations and financial results.

The oil and gas industry, as a whole, suffers from an aging workforce and a shortage of qualified and experienced personnel. Our operations and financial results may be adversely impacted due to difficulties in attracting and retaining such personnel within our Company or within companies that provide materials and services to the industry. The substantial increase in oil prices in 2010 and 2011 has resulted in increased drilling and construction activity in the industry and shortages of personnel and equipment are present in our primary focus areas. Further, our plans will likely require access to services and oil field equipment. Such equipment and operating personnel are currently in short supply.

Restrictions in any future credit agreements may prevent us from engaging in some beneficial transactions.

We are seeking to enter into credit agreements with financial institutions to fund a portion of our anticipated capital requirements. To obtain funds under credit agreements we may be required to accept operating restrictions which would impair or prevent us from future transactions we deem to be beneficial to us.

Competition for experienced technical personnel may negatively impact our operations.

Our acquisition strategy’s success could depend, in part, on our ability to attract and retain experienced professional personnel. The loss of any key executives or other key personnel could have a material adverse effect on our operations. The scope of our operations and our future will depend on our ability to attract and retain qualified personnel, particularly individuals with a strong background in geology, geophysics, engineering and operations.

Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that could adversely affect our financial condition and results of operations.

Our success depends on the results of our exploitation, exploration, development and production activities. Oil and natural gas exploration and production activities are subject to numerous significant risks some of which are beyond our control; including the risk that drilling will not result in commercially viable oil or natural gas production. Decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in large part on our proper evaluation and assessment of data obtained through geophysical and geological analyses, production data, and engineering studies. Our evaluations and assessments could ultimately prove to be incorrect. Significant aspects of costs of drilling, completing and operating wells are often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can render a particular project uneconomical. Further, many factors may curtail, delay or cancel drilling, including:

•

Shortages of or delays in obtaining equipment and qualified personnel such as we are currently experiencing;

•

Pressure or irregularities in geological formations;

•

Equipment failures or accidents;

•

Adverse weather conditions, such as those experienced during the first half of 2011;

•

Reductions in oil and natural gas prices;

•

Issues associated with property titles; and

•

Delays imposed by or resulting from compliance with regulatory requirements.

Volatile oil and natural gas prices could adversely affect our financial condition and results of operations.

Our most significant market risk is the price of crude oil and natural gas. Management expects energy prices to remain volatile and unpredictable. Moreover, oil and natural gas prices result from numerous factors that are outside of our control, including:

•

Economic and energy infrastructure disruptions caused by geopolitical factors including but not limited to embargoes and sanctions on major producing countries and actual or threatened acts of war, or terrorist activities particularly with respect to oil producers in the Middle East, Nigeria and Venezuela;

•

Weather conditions, such as hurricanes, including energy infrastructure disruptions resulting from those conditions;

•

Changes in the global oil supply, demand and inventories;

•

Changes in domestic natural gas supply, demand and inventories;

•

The price and quantity of foreign imports of oil;

•

Political conditions in or affecting other oil-producing countries;

•

General economic conditions in the United Stated and worldwide;

•

The level of worldwide oil and natural gas exploration and production activity;

•

Technological advances affecting energy consumption; and

•

The price and availability of alternative fuels.

Lower oil and natural gas prices not only decrease revenues on a per unit of production basis, but also may reduce the amount of oil and natural gas that we can economically produce negatively impacting estimates of our economically recoverable proved reserves. Substantial or extended declines in oil or natural gas prices may materially and adversely affect our financial condition, results of operations, liquidity and ability to finance operations and planned capital expenditures.

We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations.

Oil and natural gas exploration, drilling and production activities are subject to numerous operating risks including the possibility of:

•

Blowouts, fires and explosions;

•

Personal injuries and death;

•

Uninsured or underinsured losses;

•

Unanticipated, abnormally pressured formations;

•

Mechanical difficulties, such as stuck oil field drilling and service tools and casing collapses; and

•

Environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater and shoreline contamination.

Any of these operating hazards could cause damage to properties, serious injuries, fatalities, oil spills, discharge of hazardous materials, remediation and clean-up costs, and other environmental damages, which could expose us to significant liabilities.

Seeking to grow our business by purchase of production, expanding existing production, and exploration subjects us to development and other risks.

The search for commercial quantities of oil and natural gas as a business is highly risky. We cannot provide investors with any assurance that any properties in which we obtain a mineral interest will contain commercially exploitable quantities of oil and/or gas. The exploration expenditures to be made by us may not result in the discovery of commercial quantities of oil and/or gas. Problems such as unusual or unexpected formations or pressures, premature declines of reservoirs, invasion of water into producing formations and other conditions involved in oil and gas exploration often result in unsuccessful exploration efforts. If we are unable to find commercially exploitable quantities of oil and gas, and/or we are unable to commercially extract such quantities, we may be forced to abandon or curtail our business plan, and as a result, any investment in us may become worthless.

Future oil and gas price declines or unsuccessful exploration efforts may result in write-downs of our exploration and production asset carrying values.

We follow the successful efforts method of accounting for our oil and gas properties. All property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending the determination of whether proved reserves have been discovered. If proved reserves are not discovered with an exploratory well, the costs of drilling the well are expensed. The capitalized costs of our oil and gas properties, on a field basis, cannot exceed the estimated future net cash flows of that field. If net capitalized costs exceed future net revenues, we must write down the costs of each such field to our estimate of fair market value. Unproved properties are evaluated at the lower of cost or fair market value. Accordingly, a significant decline in oil or gas prices or unsuccessful exploration efforts could cause a future write-down of capitalized costs.

We review the carrying value of our proved oil and gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The impairment analysis is based on then current oil and gas prices in effect. Once incurred, a write-down of oil and gas properties cannot be reversed at a later date even if oil or gas prices increase.

Future oil and gas price declines may affect our ability to raise capital.

If oil and gas prices decrease there will be a corresponding negative impact on the value of our reserves. This could negatively affect our ability to borrow funds or raise equity capital.

Competition in our industry is intense, and many of our competitors have greater financial and technical resources than we do.

We face intense competition from major oil companies, independent oil and gas exploration and production companies, financial buyers and institutional and individual investors who are actively seeking oil and gas properties, along with the equipment, expertise, labor and materials required to operate oil and gas properties. Many of our competitors have financial and technical resources vastly exceeding those available to us, and many oil and gas properties are sold in a competitive bidding process in which our competitors may be able to pay more for development prospects and productive properties or in which our competitors have technological information or expertise to evaluate and successfully bid for the properties that is not available to us. In addition, shortages of equipment, labor or materials as a result of intense competition may result in increased costs or the inability to obtain those resources as needed. We may not be successful in acquiring and developing profitable properties in the face of this competition.

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

Our internal controls and operations are subject to extensive regulation and reporting obligations and as of June 30, 2012, we concluded that our disclosure controls and procedures were not effective. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” beginning on page 23. 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. Because of its inherent limitations, effective internal control over financial reporting may not prevent or detect misstatements. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet certain reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our shares of common stock.

If we learn of any title defects on the properties we own or acquire, it could have a material adverse effect on our operations and profitability.

We may not be the record owner of interest in our properties and may rely instead on contracts with the owner or operator of the property or assignment of leases, pursuant to which, among other things, we have the right to have our interest placed of record. As is customary in the oil and gas industry, a preliminary title examination will be conducted at the time properties or interests are acquired by us. Prior to commencement of operations on such acreage and prior to the acquisition of properties, a title examination will usually be conducted and significant defects remedied before proceeding with operations or the acquisition of proved properties, as appropriate.

Our producing properties are subject to royalty, overriding royalty and other interests customary in the industry, liens incident to agreements, current taxes and other burdens, minor encumbrances, easements and restrictions. Although we are not aware of any material title defects or disputes with respect to our current and prospective acreage acquisitions, to the extent such defects or disputes exist, we could suffer title failures.

Our officers and directors are engaged in other business activities and conflicts of interest have arisen in their daily activities which may not be resolved in our favor.

Certain conflicts of interest exist between us and our officers and directors. Officers or directors may bring energy prospects to us in which they have an interest. They have other business interests to which they devote their attention, and will be expected to continue to do so. They will also devote management time to our business. As a result, conflicts of interest or potential conflicts of interest may arise from time to time that can be resolved only through the officers and directors exercising such judgment as is consistent with fiduciary duties to their other business interests and to us. See “Certain Relationships and Related Transactions” beginning on page 38 of this prospectus.

Insurance may not fully recover potential losses.

Although we believe that we are reasonably insured against losses to wells and associated equipment, potential operational related losses could result in a loss of our reserves and properties and materially reduce our ability to self-fund exploration and development activities and property acquisitions. The insurance market, in general, and the energy insurance market in particular, have experienced substantial cost increases over recent years, resulting from significant losses associated with commercial losses. The potential for loss, however, cannot be accurately or reasonably predicted. If we incur substantial damages or liabilities that are not fully covered by insurance or are in excess of policy limits, then our business, results of operations, and financial condition could be materially affected. Also, as is customary in the oil and gas business, we do not carry business interruption insurance. In the future, it is also possible that we will further modify insurance coverage or determine not to purchase some insurance because of high insurance premiums.

Our failure to successfully identify, complete and integrate future acquisitions of properties or businesses could reduce any earnings we may achieve.

There is intense competition for acquisition opportunities in our industry for attractive oil and gas properties and other exploration and production. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Completed acquisitions could require us to invest further in operational, financial and management information systems and to attract, retain, motivate and manage effectively additional employees. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our earnings and growth. Our financial position and results of operations may fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods.

Negative or downward revisions of oil and gas reserve estimates could adversely affect the trading price of our common stock. Oil and gas reserves and the standardized measure of cash flows represent estimates, which may vary materially over time due to many factors.

The market price of our common stock may be subject to significant decreases due to decreases in our estimated reserves, our estimated cash flows and other factors. Estimated reserves may be subject to downward revision based upon future production, results of future development, prevailing oil and gas prices, prevailing operating and development costs, SEC rules related to proved undeveloped reserves and other factors. There are numerous uncertainties and uncontrollable factors inherent in estimating quantities of oil and gas reserves, projecting future rates of production, and timing of development expenditures.

The estimates of future net cash flows from proved reserves and the standardized measure of proved reserves are based upon various assumptions about prices and costs and future production levels that may prove to be incorrect over time. Any significant variance from the assumptions could result in material differences in the actual quantity of reserves and amount of estimated future net cash flows from estimated oil and gas reserves.

In addition, SEC rules generally require that proved undeveloped reserves that have not been drilled within five years be reclassified out of estimates of proved reserves; although such technically and economically recoverable reserves may be still owned or controlled by us. Accordingly, given the shortages of materials, equipment and human resources prevailing in the industry and also current low natural gas prices we may not drill certain proved undeveloped locations within the established five year time frame and therefore we may be required to reclassify such reserves out of our estimated proved undeveloped reserves. The effect of reclassifying such reserves would result in decreases in estimated proved reserve quantities and therefore could result in decreases in net income and earnings per share, resulting from increased depletion expense and possible impairments. These effects could have an adverse effect on our stock price.

Our properties are subject to influence by other parties that do not allow us to proceed with explorations and expenditures as we may desire.

We do not operate any of our properties. Joint ownership is customary in the oil and gas industry and is generally conducted under the terms of a joint operating agreement (“JOA”), where a single working interest owner is designated as the “operator” of the property. All of our producing oil and gas properties are operated by DNR, an affiliate of one of our officers and directors, Charles Davis. Thus, drilling and operating decisions are not within our sole control. If we disagree with the decision of this operator, we may be required, among other things, to postpone the proposed activity or decline to participate. If we decline to participate, we might be forced to relinquish our interest through “in-or-out” elections or may be subject to certain non-consent penalties, as provided in a JOA. In-or-out elections may require a joint owner to participate, or forever relinquish its position. Non-consent penalties typically allow participating working interest owners to recover from the proceeds of production, if any, and an amount equal to 200% to 500% of the non-participating working interest owner’s share of the cost of such operations.

Certain federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated or curtailed as a result of future legislation.

Among the changes contained in the Obama Administration’s Fiscal Year 2013 budget proposal, released by the Office of Management and Budget on February 13, 2012, is the elimination or deferral of certain U.S. federal income tax deductions and credits currently available to domestic oil and gas exploration companies. Such changes include, but are not limited to, (i) the elimination of current deductions for intangible drilling and development costs; (ii) the elimination of the deduction for certain U.S. production activities for oil and gas properties; (iii) an extension of the amortization period for certain geological and geophysical expenditures and (iv) the repeal of the enhanced oil recovery credit. Some of these same proposals to repeal or limit oil and gas tax deductions and credits have been included in legislation that has recently been considered by Congress. It is unclear whether any such changes will be enacted or how soon such changes could be effective. The passage of any legislation as a result of the budget proposal, or the passage of bills containing similar changes in U.S. federal income tax law could eliminate or defer certain tax deductions and credits that are currently available with respect to oil and gas exploration and development and could negatively affect our financial results.

The nature of our business and assets may expose us to significant compliance costs and liabilities.

Our operations involving the exploration, production, storage, treatment, and transportation of liquid hydrocarbons, including crude oil, are subject to stringent federal, state, and local laws and regulations governing the discharge of materials into the environment. Our operations are also subject to laws and regulations relating to protection of the environment, operational safety, and related employee health and safety matters. Compliance with all of these laws and regulations may represent a significant cost of doing business. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties; the imposition of investigatory and remedial liabilities; and the issuance of injunctions that may restrict, inhibit or prohibit our operations; or claims of damages to property or persons.

Compliance with environmental laws and regulations may require us to spend significant resources.

Environmental laws and regulations may: (1) require the acquisition of a permit before well drilling commences; (2) restrict or prohibit the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities; (3) prohibit or limit drilling activities on certain lands lying within wetlands or other protected areas; and (4) impose substantial liabilities for pollution resulting from past or present drilling and production operations. Moreover, changes in Federal and state environmental laws and regulations, as well as how such laws and regulations are administered, could occur and may result in more stringent and costly requirements which could have a significant impact on our operating costs. In general, under various applicable environmental regulations, we may be subject to enforcement action in the form of injunctions, cease and desist orders and administrative, civil and criminal penalties for violations of environmental laws. We may also be subject to liability from third parties for civil claims by affected neighbors arising out of a pollution event. Laws and regulations protecting the environment may, in certain circumstances, impose strict liability rendering a person liable for environmental damage without regard to negligence or fault on the part of such person. Such laws and regulations may expose us to liability for the conduct of or conditions caused by others, or for our acts which were in compliance with all applicable laws at the time such acts were performed. We believe we are in compliance with applicable environmental and other governmental laws and regulations. In recent years, increased concerns have been raised over the protection of the environment. Legislation to regulate the emissions of greenhouse gases has been introduced in Congress, and there has been a wide-ranging policy debate, both nationally and internationally, regarding the impact of these gases and possible means for their regulation. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. Also, the EPA has recently undertaken significant efforts to collect information regarding greenhouse gas emissions and their effects.

Climate change legislation or regulations restricting emissions of “greenhouse gasses” could result in increased operating costs and reduced demand for crude oil and natural gas that we produce.

In December 2009, the U.S. Environmental Protection Agency, (“EPA”) determined that emissions of carbon dioxide, methane, and other greenhouse gases (“GHGs”), present an endangerment to public health and the environment because emissions of such gasses are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climate changes. Based on these findings the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the federal Clean Air Act. The EPA has adopted two sets of rules regulating greenhouse gas emissions under the Clean Air Act, one set of rules limit emissions of GHGs from motor vehicles and the other set of rules require certain Prevention of Significant Deterioration (“PSD”) and Title V permit requirements for GHG emissions from certain large stationary sources. The EPA rules have tailored the PSD and Title V permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States, including, among others, certain oil and natural gas production facilities, which may include certain of our operations, on an annual basis.

In addition, the U.S. Congress has from time to time considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. The adoption of any legislation or regulations that requires reporting of GHGs or otherwise limits emissions of GHGs from our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas that we produce.

Federal, state, and local legislative and regulatory initiatives relating to hydraulic fracturing, as well as government reviews of such activities, could result in increased costs, additional operating restrictions or delays, and adversely affect our production and/or ability to book future reserves.

Hydraulic fracturing involves the injection of water, sand, and chemical additives under pressure into a targeted subsurface formation. The water and pressure create fractures in the rock formations, which are held open by the grains of sand, enabling the oil or natural gas to flow to the wellbore. The process is typically regulated by state oil and natural gas commissions; however, the EPA, recently asserted federal regulatory authority over certain hydraulic-fracturing activities involving diesel under the Safe Drinking Water Act and has begun the process of drafting guidance documents related to this newly asserted regulatory authority. In November 2011, the EPA announced its intent to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. In February 2012, the U.S. Department of the Interior (the “DOI”) released draft regulations governing hydraulic fracturing on federal and Indian oil and gas leases to require disclosure of information regarding the chemicals used in hydraulic fracturing, advance approval for well-stimulation activities, mechanical integrity testing of casing, and monitoring of well-stimulation operations. In addition, the U.S. Congress, from time to time, has considered adopting legislation intended to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic-fracturing process. In the event that a new, federal level of legal restrictions relating to the hydraulic-fracturing process are adopted in areas where we currently or in the future plan to operate, we may incur additional costs to comply with such federal requirements that may be significant in nature, and also could become subject to additional permitting requirements and cause us to experience added delays or curtailment in the pursuit of exploration, development, or production activities.

There are also certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic-fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic-fracturing practices, and a committee of the U.S. House of Representatives has conducted an investigation of hydraulic-fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic-fracturing activities and plans to propose these standards by 2014. In addition, the U.S. Department of Energy is conducting an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic-fracturing completion methods. These ongoing or proposed studies, depending on any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act or other regulatory mechanisms.

In addition, some states have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations. For example, Colorado, Montana, Pennsylvania, Louisiana, Texas, and Wyoming, have adopted, and other states are considering adopting, regulations that could impose new or more stringent permitting, disclosure, and additional well-construction requirements on hydraulic-fracturing operations. For example, Texas adopted a law in June 2011 requiring disclosure to the Railroad Commission of Texas and the public of certain information regarding the components used in the hydraulic-fracturing process. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit drilling in general and/or hydraulic fracturing in particular. These regulations will affect our operations, increase our costs of exploration and production and limit the quantity of natural gas and oil that we can economically produce to the extent that we use hydraulic fracturing. A major risk inherent in our drilling plans is the need to obtain

drilling permits from state and local authorities on a timely basis following leasing. Delays in obtaining regulatory approvals, drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could have a material adverse effect on our ability to explore on or develop our properties. Additionally, the natural gas and oil regulatory environment could change in ways that might substantially increase our financial and managerial costs to comply with the requirements of these laws and regulations and, consequently, adversely affect our profitability. Furthermore, these additional costs may put us at a competitive disadvantage compared to larger companies in the industry which can spread such additional costs over a greater number of wells and larger operating staff.

We are exposed to trade credit risk in the ordinary course of our business activities.

We are exposed to risks of loss in the event of nonperformance by our vendors, customers and by counterparties to our hedging arrangements. Some of our vendors, customers and counterparties may be highly leveraged and subject to their own operating and regulatory risks. Many of our vendors, customers and counterparties finance their activities through cash flow from operations, the use of debt or the issuance of equity. Even if our credit reviews are satisfactory, we may experience financial losses in our dealings with other parties. Any increase in the nonpayment or nonperformance by our vendors, customers and/or counterparties could adversely affect our financial condition and results of operation.

Risks Related to Our Common Stock

Investors may be diluted in future Common Stock offerings.

The holders of our common stock have no preemptive rights, and the issuance of additional shares of common stock by us may result in a commensurate reduction in an individual shareholder’s percentage ownership in us. The value of an investor’s investment in our convertible preferred stock may decrease to the extent that such dilution reduces the fair value of the shares of common stock.

Our common share price has fluctuated in the past and may continue to fluctuate in the future

The market price of our common shares in the over-the-counter market has experienced significant volatility and may continue to fluctuate significantly. The market price of our common shares may be significantly affected by factors such as the announcements of agreements and technological innovations by us or our competitors. In addition, while we cannot assure you that any securities analysts will initiate or maintain research coverage of our company and our shares, any statements or changes in estimates by analysts initiating or covering our shares or relating to the oil and gas industry could result in an immediate and adverse effect on the market price of our shares. Further, we cannot predict the effect, if any, that market sales of shares or the availability of shares for sale will have on the market price of the shares prevailing from time to time. Sales of a substantial number of shares or the perception that such sales could occur following the date of this prospectus, could have a material adverse effect on the market price of our shares.

Trading in shares of companies, such as ours, have been subject to extreme price and volume fluctuations that have been unrelated or disproportionate to operating or other performance.

Trading on the OTC Market may be volatile and sporadic, which could depress the market price of our common stock and make it difficult for our shareholders to resell their shares.

Our common stock is quoted on the OTC Market. Trading in stock quoted on the OTC Bulletin Board is often thin and characterized by wide fluctuations in trading prices due to many factors that may have little to do with our operations or business prospects. This volatility could depress the market price of our common stock for reasons unrelated to operating performance. Moreover, the OTC Market is not a stock exchange, and trading of securities on the OTC Market is often more sporadic than the trading of securities listed on other stock exchanges such as the NASDAQ Stock Market, New York Stock Exchange or American Stock Exchange. Accordingly, our shareholders may have difficulty reselling any of their shares.

Our common stock is a penny stock. Trading of our stock may be restricted by the SEC’s penny stock regulations and the FINRA’s sales practice requirements, which may limit a shareholders ability to buy and sell our stock.

Our common stock is a penny stock. The SEC has adopted Rule 15g-9 which generally defines penny stock to be any equity security that has a market price (as defined) less than $5.00 per share or an exercise price of less than $5.00 per share, subject to certain exceptions. Our securities are covered by the penny stock rules, which impose additional sales practice requirements on broker-dealers who sell to persons other than established customers and accredited investors. The term accredited investor refers generally to institutions with assets in excess of $5,000,000 or individuals with a net worth in excess of $1,000,000 or annual income exceeding $200,000 or $300,000 jointly with their spouse. The penny stock rules require a broker-dealer, prior to a transaction in a penny stock not otherwise exempt from the rules, to deliver a standardized risk disclosure document in a form prepared by the SEC which provides information about penny stocks and the nature and level of risks in the penny stock market. The broker-dealer must also provide the customer with current bid and offer quotations for the penny stock, the compensation of the broker-dealer and its

salesperson in the transaction and monthly account statements showing the market value of each penny stock held in the customer’s account. The bid and offer quotations, and the broker-dealer and salesperson compensation information, must be given to the customer orally or in writing prior to effecting the transaction and must be given to the customer in writing before or with the customer’s confirmation. In addition, the penny stock rules require that prior to a transaction in a penny stock not otherwise exempt from these rules, the broker-dealer must make a special written determination that the penny stock is a suitable investment for the purchaser and receive the purchaser’s written agreement to the transaction. These disclosure requirements may have the effect of reducing the level of trading activity in the secondary market for the stock that is subject to these penny stock rules. Consequently, these penny stock rules may affect the ability or willingness of broker-dealers to trade our securities. We believe that the penny stock rules discourage broker-dealer and investor interest in, and limit the marketability of, our common stock.

FINRA sales practice requirements may also limit a shareholders ability to buy and sell our stock.

In addition to the penny stock rules promulgated by the SEC, which are discussed in the immediately preceding risk factor, FINRA rules require that in recommending an investment to a customer, a broker-dealer must have reasonable grounds for believing that the investment is suitable for that customer. Prior to recommending speculative low priced securities to their non-institutional customers, broker-dealers must make reasonable efforts to obtain information about the customer’s financial status, tax status, investment objectives and other information. Under interpretations of these rules, FINRA believes that there is a high probability that speculative low priced securities will not be suitable for at least some customers. FINRA requirements make it more difficult for broker-dealers to recommend that their customers buy our common stock, which may limit the ability to buy and sell our stock and have an adverse effect on the market value for our shares.

The sale of our common stock by the selling shareholders may depress the price of our common stock due to the limited trading market which exists.

Due to a number of factors, including the lack of listing of our common stock on a national securities exchange, the trading volume in our common stock has historically been limited. As a result, the sale of a significant amount of common stock by the selling shareholders may depress the price of our common stock. As a result, you may lose all or a portion of your investment.

There are a substantial number of shares of our common stock eligible for future sale in the public market. The sale of a large number of these shares could cause the market price of our common stock to fall.

There were 7,979,803 shares of our common stock outstanding as of October 16 2012. As of that date, members of our management and their affiliates owned approximately 2,212,720 shares of our common stock, representing 25.9% of our outstanding common stock. Sale of a substantial number of these shares would likely have a significant negative effect on the market price of our common stock, particularly if the sales are made over a short period of time.

If our shareholders, particularly management and their affiliates, sell a large number of shares of our common stock, the market price of shares of our common stock could decline significantly. Moreover, the perception in the public market that our management and affiliates might sell shares of our common stock could depress the market price of those shares.

Because we have no plans to pay dividends on our common stock, investors must look solely to stock appreciation for a return on their investment in us.

We have never declared or paid cash dividends on our common stock. We currently intent to retain all future earnings and other cash resources, if any, for the operations and development of our business and do not anticipate paying cash dividends in the foreseeable future. Payment of any future dividends will be at the discretion of our board of directors after taking into account many factors, including our financial condition, operating results, current and anticipated cash needs and plans for expansions. In addition, we may not pay cash dividends on our common stock for so long as any shares of our convertible preferred stock are outstanding. Any future dividends may also be restricted by any loan agreements which we may enter into from time to time and from the issuance of preferred stock should we decide to do so in the future.

USE OF PROCEEDS

We will not receive any of the proceeds from the sale of common stock by the selling shareholders.

BUSINESS AND PROPERTIES

Company Overview

In September 2006, we acquired a gas gathering system (pipeline and compressor station related assets) in Campbell County, Wyoming. This system was constructed in late 2001 and began operations early in 2002. The system consists of 4.5 miles of 8-inch coated steel pipeline. During the first half of 2011, this pipeline was transporting approximately 900,000 Mcf (thousand cubic feet) of coal bed methane per day and was cash flowing from its operations until June 2011 when the operator shut-in the coal bed methane wells due to the low prices received for the natural gas produced. This system has a current throughput capacity of approximately 4 million cubic feet of gas per day.

On May 25, 2011, the Company entered into a purchase and sale agreement and other related agreements and documents with Tucker Family Investments, LLLP; DNR Oil & Gas, Inc. which we refer to as DNR; and Tindall Operating Company, which we refer to as Tindall, and collectively we refer to these parties as the Sellers, for the purchase of certain oil and gas operating properties in Colorado, Kansas, Wyoming, and Montana, which we refer to collectively as the original purchase and sale agreement. DNR is owned primarily by an officer and director of the Company, Charles B. Davis. The consideration for the purchase was determined by bargaining between management of the Company and Mr. Davis, and the Company used reports of independent engineering firms to analyze the purchase price. The base purchase price for the properties was $10 million, of which the Company paid a nonrefundable down payment of $500,000 and the remaining $9.5 million was financed by the Sellers pursuant to a promissory note due July 1, 2011. The Company was unable to arrange the funding to pay the $9.5 million promissory note due on July 1, 2011, and therefore, the note was not paid. On July 29, 2011, the Company and the Sellers entered into an amended and restated purchase and sale agreement regarding the acquisition by the Company of the oil and gas properties originally sought to be purchased. The material terms of the agreement, as amended, were a base purchase price for the properties of $11 million to be paid by an initial payment of $900,000, comprised of (i) a credit in the amount of $500,000 previously paid by the Company in connection with the original purchase and sale agreement; and (ii) $400,000 in funds paid contemporaneously with the execution of the amended purchase and sale agreement. The remaining principal balance of the base purchase price in the amount of $10,100,000, together with interest at the monthly interest rate of 0.83% was to be paid to Sellers in three monthly payments, with $3,700,000 due August 15, 2011 (extended to August 31, 2011), and $3,200,000 due on each of September 15, 2011 and October 15, 2011. All payments were paid in full on September 29, 2011. The Company may be obligated to make additional payments under the amended purchase and sale agreement if the Company increases its proven producing net oil reserves or net gas reserves by drilling or recompletion on certain of the acquired properties in Colorado and Kansas, then the Company will pay $250,000 for every 20,000 bbls or 150,000 mcf increase respectively. If the Nymex prices for oil and/or gas stay above certain thresholds for more than 60 days, the Company will also be required to pay an additional $250,000 as each threshold is exceeded for more than 60 consecutive days. Cumulative payments under the additional purchase price factor for the Colorado and Kansas properties are limited to $5 million. The Company will also make similar payments to the Sellers if the Company increases reserves in the Wyoming and Montana properties, and the Company will make additional payments under a formula by which Sellers and the Company will share proceeds of sales or production from untapped formations on the properties acquired in Wyoming and Montana. Cumulative payments under the additional purchase price factor for the Wyoming and Montana properties are limited to $20 million. The aggregate of all additional purchase price payments from all factors and all states is capped at $25 million. Due to consideration retained by the related party sellers from sales of properties through the second quarter of 2012, and $250,000 of consideration payable in December 2012 and April 2013 due to sustained increases in oil prices over $100 per barrel, the maximum future consideration has been reduced by approximately $5.2 million to $19.8 million as of June 30, 2012.

In connection with the amended purchase and sale agreement, the Company obtained the right to receive a portion of the proceeds from sale of certain of the properties that could be sold before payment in full of the base purchase price and assignment of the properties to the Company. Certain properties were sold on August 23, 2011 and the Company received $5,101,047 for its share of the net proceeds on the sale. The Company applied its net proceeds to the payments due under the amended purchase and sale agreement. On September 29, 2011 the Company paid the balance of $5,120,194 that included $121,241 of interest. The Company recognized a gain on the sale of these assets of $2,479,934, which is included in non-operating income for the year ended December 31, 2011. Also, the Company, as part of the amended purchase and sale agreement, received the production of oil and gas from the purchased properties beginning April 1, 2011 and was responsible for the related lease operating expenses from April 1 as well. The net proceeds of the production, less production taxes, and lease operating expenses from April 1, 2011 to July 29, 2011 of $766,812 was applied to reduce the carrying costs of the oil and natural gas properties.

Part of our strategy is to monitor the current production of our properties, seek to develop them with infield drilling, and explore sales and purchases of additional leases and operating wells with upside. We are currently evaluating several opportunities for drilling in Kansas and Colorado. We have had preliminary discussions on properties for sale, joint venture, or farm-out in Wyoming. However, we need to obtain additional capital resources before we can execute a plan for the development in Wyoming.

The following table provides information regarding our oil and natural gas producing assets and operations located in the state where the properties are located as for December 31, 2011.


												2011 Average
	Proved Reserves at 2011 Year-End							Productive				Monthly
	Quantity		Pre-Tax		%			Wells During 2011				Production
State	(BOE) *(a)*		PV 10% *(b)*		Oil *(c)*			Gross		Net *(d)*		(BOE) *(e)*
Wyoming		222,987	$	4,208,112		78.9	%		40.0		34.3		2,198
Kansas		159,586		4,377,810		100.0	%		5.0		3.4		597
Colorado		124,105		2,259,149		31.8	%		8.0		7.7		778
Montana		6,223		20,374		0.0	%		2.0		1.4		53

		512,901	$	10,865,445		73.1	%		55.0		46.8		3,626

(a)

BOE is defined as one barrel of oil equivalent determined using the ratio of six Mcf of natural gas to one barrel of oil.

(b)

The prices used to calculate this measure were $83.79 per barrel of oil and $5.84 per Mcf for natural gas. These prices were computed by applying the SEC-mandated 12 month arithmetic average of the first of month price for January through December 31, 2011, which resulted in benchmark prices of $96.19 per barrel for crude oil and $4.12 per MMbtu for natural gas. Benchmark prices were further adjusted on a well by well basis for transportation, quality and basis differentials to arrive at the prices used for this report.

(c)

Computed based on BOE using the ratio of six Mcf of natural gas to one barrel of oil.

(d)

Net wells are the sum of our fractional working interests in gross wells.

(e)

2011 average monthly production is for the entire year ended December 31, 2011, although the Company did not acquire its ownership interest in the properties until the third quarter of 2011.

Reconciliation of Standardized Measure to PV10

PV10 is the estimated present value of the future net revenues from our proved oil and natural gas reserves before income taxes discounted using a 10% discount rate. PV10 is considered a non-GAAP financial measure because it does not include the effects of future income taxes, as is required in computing the standardized measure of discounted future net cash flows. We believe that PV10 is an important measure that can be used to evaluate the relative significance of our oil and natural gas properties and that PV10 is widely used by securities analysts and investors when evaluating oil and natural gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes to be paid, we believe the use of a pre-tax measure provides greater comparability of assets when evaluating companies. We believe that many other companies in the oil and natural gas industry calculate PV10 on the same basis. PV10 is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting income taxes. The table below provides a reconciliation of our standardized measure of discounted future net cash flows to our PV10 value:


	Standardized Measure			PV10
Future cash inflows	$	36,256,572		$	36,256,572
Future production costs		(14,467,156	)		(14,467,156	)
Future development costs		(964,486	)		(964,486	)
Future income taxes		(4,687,201	)		—

Future net cash flows		16,137,729			20,824,930

10 percent annual discount		(7,795,729	)		(9,959,485	)

Discounted future net cash flows	$	8,342,000		$	10,865,445

The difference between the standardized measure of $8,342,000 and PV10 of $10,865,445 is $2,523,445, which is due to income taxes included in the standardized measure as follows:


Undiscounted income taxes	$	4,687,201
Impact of 10% discount factor		(2,163,756	)

Discounted impact of income taxes	$	2,523,445

Business Strategy

Our business strategy is three-fold in approach.

•

We plan to and have acquired oil and natural gas operating properties that will provide for the operations of the Company;

•

We expect to seek to acquire leases that have development possibility either for us to drill and or with other companies on a joint venture or farm-out basis. Part of this plan would include the possibility of selling leases and retaining an overriding royalty in the property and a right to buy back into future development; and

•

We are looking for acquisitions of producing properties with future development.

Competitive Business Conditions

The oil and natural gas industry is intensely competitive, and we compete with numerous other companies engaged in the exploration and production of oil and gas. Many 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 are in many instances able to pay more for exploratory prospects and productive oil and natural gas properties. Many of our competitors also have more resources to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or technical resources permit.

Our larger competitors have the resources to be better able to absorb the burden of current and future federal, state, and local laws and regulations more easily than we can, which adversely affects our competitive position. Our ability to locate reserves and acquire interests in properties in the future will be dependent upon our ability and resources to evaluate and select suitable properties and consummate transactions in this highly competitive environment. In addition, we may be at a disadvantage in acquiring producing oil and natural gas properties and bidding for exploratory prospects because we have fewer financial and technical resources than other companies in our industry.

Marketing and Customers

The market for oil and natural gas that we produce depends on factors beyond our control, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of natural gas pipelines and other transportation facilities, demand for oil and natural gas, the marketing of competitive fuels and the effects of state and federal regulation. The oil and 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, as adjusted for transportation and quality. 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 currently rely on our related party operator to market and sell our production.

Seasonality—Gathering and Processing

Generally, but not always, the demand and price levels for natural gas increase during the colder winter months and decrease during the warmer summer months. More recently, historical natural gas prices have been at ten year lows. In addition, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Seasonal anomalies such as mild winters and summers sometimes lessen these fluctuations.

Foreign Operations and Export Sales

We do not have any interests, production facilities, or operations in foreign countries.

Governmental Regulations

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

Oil and Natural Gas Production

Our oil and natural gas exploration, production and related operations are subject to extensive rules and regulations promulgated by federal, state, and local authorities and agencies. Certain 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 has increased our cost of doing business and affected 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.

Transportation of Natural Gas

Historically, the transportation of natural gas in interstate commerce has been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and regulations issued under those Acts by the Federal Energy Regulatory Commission ( FERC ).

In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future.

Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. The FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. The FERC’s orders are intended to foster increased competition within all phases of the natural gas industry.

We cannot accurately predict whether the FERC’s actions will achieve the goal of increasing competition. Therefore, we cannot provide any assurance that the less stringent regulatory approach established by the FERC will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects our competitors

Intrastate natural gas transportation is subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors.

Environmental Matters

Our operations and properties are, like the oil and natural gas industry in general, subject to extensive and changing federal, state and local laws and regulations relating to both environmental protection, including the generation, storage, handling, emission, transportation and discharge of materials into the environment, and safety and health. The recent trend in environmental regulation is generally toward stricter standards, and this trend is likely to continue. These laws and regulations may require a permit or other authorization before construction or drilling commences and for certain other activities; limit or prohibit access, seismic acquisition, construction, drilling and other activities on certain lands lying within wilderness and other protected areas; impose substantial liabilities for pollution resulting from our operations; and require the reclamation of certain lands.

The permits required for many of our operations are subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce compliance with their regulations, and violations are subject to fines, injunctions, or both. In the opinion of management, we are in substantial compliance with current applicable environmental laws and regulations, and we have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on us, as well as the oil and natural gas industry in general. The Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) and comparable state statutes impose strict and arguably joint and several liabilities on owners and operators of certain 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 Resource Conservation and Recovery Act (RCRA) and comparable state statutes govern the disposal of “solid waste” and “hazardous waste” and authorize imposition of substantial fines and penalties for noncompliance. Although CERCLA currently excludes petroleum from its definition of “hazardous substance,” state laws affecting our operations 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.

Federal regulations require certain owners or operators of facilities that store or otherwise handle oil, such as us, to prepare and implement spill prevention, control countermeasure and response plans relating to the possible discharge of oil into surface waters. The Oil Pollution Act of 1990 (OPA) contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States. For onshore and offshore facilities that may affect waters of the United States, the OPA requires an operator to demonstrate financial responsibility. Regulations are currently being developed under federal and state laws concerning oil pollution prevention and other matters that may impose additional regulatory burdens on us. In addition, the Clean Water Act and analogous state laws require permits to be obtained to authorize discharge into surface waters or to construct facilities in wetland areas. The Clean Air Act of 1970 and its subsequent amendments in 1990 and 1997 also impose permit requirements and necessitate certain restrictions on point source emissions of volatile organic carbons (nitrogen oxides and sulfur dioxide) and particulates with respect to certain of our operations. We are required to maintain such permits or meet general permit requirements. The EPA and designated state agencies have in place regulations concerning discharges of storm water runoff and stationary sources of air emissions. These programs require covered facilities to obtain individual permits, participate in a group or seek coverage under an EPA general permit. Most agencies recognize the unique qualities of oil and natural gas exploration and production operations. We believe that we will be able to obtain, or be included under, such permits, where necessary, and to make minor modifications to existing facilities and operations that would not have a material effect on us.

Climate Change

Climate change has become the subject of an important public policy debate. Climate change remains a complex issue, with some scientific research suggesting that an increase in greenhouse gas emissions (GHGs) may pose a risk to society and the environment. The oil and natural gas exploration and production industry is a source of certain GHGs, namely carbon dioxide and methane, and future restrictions on the combustion of fossil fuels or the venting of natural gas could have a significant impact on our future operations.

Impact of Legislation and Regulation. The commercial risk associated with the exploration and production of fossil fuels lies in the uncertainty of government-imposed climate change legislation, including cap and trade schemes, and regulations that may affect us, our suppliers, and our customers. The cost of meeting these requirements may have an adverse impact on our financial condition, results of operations and cash flows, and could reduce the demand for our products.

Climate change legislation and regulations have been adopted by many states in the US; however, legislation and regulations have not been enacted at the federal level in the US or all states, although Congress and several states are considering adopting climate change legislation. The current state of development of many state and federal climate change regulatory initiatives in areas where we operate makes it difficult to predict with certainty the future impact on us, including accurately estimating the related compliance costs that we may incur.

Indirect Consequences of Regulation or Business Trends. We believe there are risks arising from the global response to climate change.

Physical Impacts of Climate Change on our Costs and Operations. There has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornados and snow or ice storms, as well as rising sea levels. Extreme weather conditions increase our costs, and damage resulting from extreme weather may not be fully insured. However, the extent to which climate change may lead to increased storm or weather hazards affecting our operations is difficult to identify at this time.

Employees

We currently have no full time or part time employees. Our officers serve us in a consulting capacity. We anticipate adding employees and are currently using independent contractors, consultants, attorneys and accountants as necessary, to complement services for operations and regulatory filings. We presently have four independent technical professionals under consulting agreements, all of whom are available to us on an as needed basis.

Intellectual Property

We do not currently have any patents, trademarks or licenses.

Oil and Natural Gas Properties

The following table lists the oil and natural gas properties we have by state and field as of December 31, 2011.


		Productive Wells				Proved Reserves		Gross		Net
States and Field	County	Gross		Net *(a)*		(BOE) *(b)*		Acres		Acres
Wyoming:
Rex Lake	Albany		8.0		8.0		36,230		963		963
Buff	Campbell		8.0		8.0		43,296		4,783		4,128
Shippy	Campbell		1.0		1.0		64,370		6,517		4,765
Bobcat Creek	Converse		2.0		1.5		14,716		5,580		4,915
Other	Various		21.0		15.8		64,375		8,671		6,524
Kansas:
Big Bow	Stanton		2.0		0.6		62,952		800		240
Granger Creek	Clark		1.0		1.0		48,568		320		320
Walz	Trego		1.0		0.9		33,040		320		288
Other	Graham		1.0		0.9		15,026		320		288
Colorado:
Gemini	Weld		2.0		2.0		40,278		1,375		1,375
Smokey Creek	Cheyenne		1.0		0.7		33,852		125		100
Wild Horse	Weld		1.0		1.0		6,404		125		125
Other	Various		4.0		4.0		43,571		375		375
Montana:
Police Coulee	Toole		2.0		1.4		6,223		253		200

			55.0		46.8		512,901		30,527		24,606

(a)

Net wells are the sum of our fractional working interests owned in gross wells.

Office Facilities

We currently lease our office space in Westminster, Colorado for $250 per month from our Chief Executive Officer.

MARKET FOR COMMON EQUITY AND

RELATED SHAREHOLDER INFORMATION

Market Information

Our common stock has been quoted on the OTCQB tier of the OTC Markets. Our trading symbol is “ARET.OTCQB”

The following table sets forth the range of high and low trading price information for our common stock for each fiscal quarter for the past two fiscal years and for the first quarter of the current fiscal years as reported by the OTC Markets Inc. and obtained from Yahoo Finance. High and low trading information which represents prices between dealers without adjustment for retail mark-ups, markdowns or commissions. On April 10, 2011, we completed a 100 for 1 reverse stock split and prices below give effect to the reverse split.


	HIGH		LOW
Year Ended December 31, 2010:
First Quarter	$	2.20	$	0.60
Second Quarter		1.65		0.85
Third Quarter		1.50		0.80
Fourth Quarter		2.30		0.90
Year Ended December 31, 2011:
First Quarter	$	8.50	$	1.05
Second Quarter		6.15		4.30
Third Quarter		5.15		2.50
Fourth Quarter		3.25		1.06
Year Ended December 31, 2012:
First Quarter	$	2.00	$	0.80
Second Quarter		1.35		0.54
Third Quarter		0.96		0.22

On October 16, 2012, the last reported sales price of our common stock as reported on the OTCQB was $.33 per share.

Holders

As of October 16, 2012, the approximate number of holders of record of shares of our common stock, our only class of trading securities, was approximately 4,100. The number of record holders of our common stock was determined from the records of our transfer agent and does not include numerous beneficial owners of our common stock whose shares are held in street name by various security brokers, dealers, and registered clearing agencies. The number of beneficial shareholders is unknown to us.

Dividends

The Company has not paid any cash dividends with respect to its common stock and it is not anticipated that the Company will pay cash dividends in the foreseeable future. Also, the Company cannot pay cash dividends on its common stock for so long as any shares of convertible preferred stock are outstanding. On March 31, 2012, the Company declared a semi-annual dividend on its convertible preferred stock of approximately $392,000 which was paid on April 2, 2012. On September 11, 2012, the Company declared a semi-annual dividend on its convertible preferred stock of approximately $392,000 which was paid on October 1, 2012.

The Securities Enforcement and Penny Stock Reform Act of 1990

The SEC has adopted rules that regulate broker-dealer practices in connection with transactions in penny stocks. Penny stocks are generally equity securities with a price of less than $5.00 (other than securities registered on certain national securities exchanges or quoted on the Nasdaq system, provided that current price and volume information with respect to transactions in such securities is provided by the exchange or system). Our common shares are currently subject to the penny stock rules.

A purchaser purchasing penny stock has limitations on the ability to sell the stock. The shares offered by this prospectus constitute penny stock under the Exchange Act. The classification of penny stock makes it more difficult for a broker-dealer to sell the stock into a secondary market, which makes it more difficult for a purchaser to liquidate his/her investment. Any broker-dealer engaged by the purchaser for the purpose of selling his or her shares in us will be subject to Rules 15g-1 through 15g-10 of the Exchange Act. Rather than creating a need to comply with those rules, some broker-dealers will refuse to attempt to sell penny stock.

The penny stock rules require a broker-dealer, prior to a transaction in a penny stock not otherwise exempt from those rules, to deliver a standardized risk disclosure document prepared by the SEC, which:

•

contains a description of the nature and level of risk in the market for penny stocks in both public offerings and secondary trading;

•

contains a description of the broker’s or dealer’s duties to the customer and of the rights and remedies available to the customer with respect to a violation to such duties or other requirements of the Exchange Act, as amended;

•

contains a brief, clear, narrative description of a dealer market, including “bid” and “ask” prices for penny stocks and the significance of the spread between the bid and ask price;

•

contains a toll-free telephone number for inquiries on disciplinary actions;

•

defines significant terms in the disclosure document or in the conduct of trading penny stocks; and

•

contains such other information and is in such form (including language, type, size and format) as the SEC shall require by rule or regulation.

The broker-dealer also must provide, prior to effecting any transaction in a penny stock, to the customer:

•

the bid and offer quotations for the penny stock;

•

the compensation of the broker-dealer and its salesperson in the transaction;

•

the number of shares to which such bid and ask prices apply, or other comparable information relating to the depth and liquidity of the market for such stock; and

•

monthly account statements showing the market value of each penny stock held in the customer’s account.

In addition, the penny stock rules require that prior to a transaction in a penny stock not otherwise exempt from those rules; the broker-dealer must make a special written determination that the penny stock is a suitable investment for the purchaser and receive the purchaser’s written acknowledgment of the receipt of a risk disclosure statement, a written agreement to transactions involving penny stocks, and a signed and dated copy of a written suitability statement. These disclosure requirements have the effect of reducing the trading activity in the secondary market for our stock. Thus, shareholders may have difficulty selling their securities.

Our Transfer Agent

ComputerShare Investor Services is the transfer agent for our Common Stock. ComputerShare can be contacted at 250 Royall Street, Canton, MA 02021.

Securities Authorized for Issuance Under Equity Compensation Plans

We do not have any equity compensation plans in effect.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

General Overview

We discuss and provide below our analysis of the following:

•

Critical accounting policies;

•

Results of operations;

•

Liquidity and capital resources;

•

Contractual obligations and commercial commitments;

•

Off-balance sheet arrangements;

•

New accounting pronouncements; and

•

Controls and procedures.

In the third quarter of 2011, we completed an acquisition of oil and natural gas properties in Montana, Wyoming, Colorado and Kansas. These properties include several proved undeveloped and probable drilling opportunities. While we have made good progress in implementing our business strategy over the past year, we believe our primary challenge over the next several months is to obtain additional financing to exploit existing drilling opportunities and possibly to acquire additional properties. We have sold some of our properties while retaining overriding royalty interests for future upside upon further development of the properties. In addition, we are in the process of reviewing several opportunities for the purchase of production and underdeveloped oil and gas leases for future development. In order to purchase properties or begin substantive drilling activities we must obtain additional financing, which cannot be assured. We rely heavily on the skills of our board members in the fields of business development, capital acquisition, corporate visibility, oil and gas development, geology and operations.

While we are optimistic about our progress on our strategy, there are no assurances that we can resolve our pressing capital needs, and although have revenue from operations, our ability to execute our plans will still be depend on our ability to raise additional capital. We have not received a commitment to finance the drilling development plan we would like to implement. We currently have created cash flow that is sufficient to pay our current expenses and convertible preferred stock dividend, but this cash flow is heavily dependent on the prices for crude oil. Any significant decreases in the prices we receive for crude oil will jeopardize our ability to generate positive cash flow and pay a dividend on our convertible preferred stock dividend ($391,875 semi-annually.) We plan to seek to obtain forms of capital financing to complete our development and drilling plans. To achieve this, we will call upon the skills of our board members in the fields of business development, capital acquisition, corporate visibility, oil and gas development, geology and operations. We cannot assure we will receive further capital, or if we do that the terms of such capital will be beneficial to us.

Further, as opportunities for participation in revenue producing projects arise, we intend that consultants and advisors will be offered compensation from revenues or interests, direct participations, royalties or other incentives from the specific projects to which they contribute. While we seek to reduce the amount of our variable costs on an ongoing basis, there is almost no way to reduce or offset our fixed expenses related to office expense, legal, accounting, transfer agent fees, reporting, corporate governance, and shareholder communications. We have to incur cash costs for the due diligence, reserve studies, audits, and legal cost for these proposed acquisitions of oil and gas properties.

Our future expectation is that monthly operating expenses will remain as low as possible until new opportunities are initiated, of which there can be no assurance, in which event the operating costs of the Company may increase relative to the need for administrative and executive staff and overhead to provide support for these new business activities.

The Company has identified the accounting policies described below as critical to its business operations and the understanding of the Company’s results of operations. The impact and any associated risks related to these policies on the Company’s business operations is discussed throughout this section where such policies affect the Company’s reported and expected financial results. The preparation of our consolidated financial statements requires the Company to make estimates and assumptions that affect the reported amount of assets and liabilities of the Company, revenues and expenses of the Company during the reporting period, and contingent assets and liabilities as of the date of the Company’s consolidated financial statements. There can be no assurance that the actual results will not differ from those estimates.

Critical Accounting Policies

The following discussion and analysis of the results of operations and financial condition are based on the Company’s consolidated financial statements that have been prepared in accordance with accounting principles generally accepted in the United States of America, which we refer to as GAAP. Our significant accounting policies are more fully described in Note 2 of the Notes to the Consolidated Financial Statements for the years ended December 31, 2010 and 2011. However, certain accounting policies and estimates are particularly important to the understanding of our financial position and results of operations and require the application of significant judgment by our management or can be materially affected by changes from period to period in economic factors or conditions that are outside the control of management. As a result, they are subject to uncertainty. In applying these policies, our management uses its judgment to determine the appropriate assumptions to be used in the determination of certain estimates. Those estimates are based on our historical operations, our future business plans and projected financial results, the terms of existing contracts, our observance of trends in the industry, information provided by our customers and information available from other outside sources, as appropriate. Actual results may differ from these estimates. All historical numbers are presented on a consolidated basis that includes all acquisitions and eliminates inter-company transactions.

Revenue Recognition

We record revenue from the sale of natural gas, NGLs and crude oil when delivery to the purchaser has occurred and title has transferred. We use the sales method to account for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold by us. In addition, we record revenue for its share of gas sold by other owners that cannot be volumetrically balanced in the future due to insufficient remaining reserves. We also reduce revenue for other owners’ gas sold by us that cannot be volumetrically balanced in the future due to insufficient remaining reserves. Our remaining over- and under-produced gas balancing positions are considered in our proved oil and gas reserves. Gas imbalances at December 31, 2011 and June 30, 2012 were not material.

Use of Estimates

Preparation of our financial statements in accordance with GAAP requires management to make various assumptions, judgments and estimates that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts initially established.

Oil and Gas Producing Activities

In January 2010, the Financial Accounting Standards Board, which we refer to as the FASB, issued authoritative oil and gas reserve estimation and disclosure guidance that was effective for the Company beginning in 2010. This guidance was issued to align the accounting oil and gas reserve estimation and disclosure requirements with the requirements in the SEC final rule, “Modernization of Oil and Gas Reporting “, which was also effective in 2010.

Our oil and gas exploration and production activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense and included within cash flows from investing activities in the Consolidated Statements of Cash Flows. The costs of development wells are capitalized whether productive or nonproductive. Oil and gas lease acquisition costs are also capitalized.

Other exploration costs, including certain geological and geophysical expenses and delay rentals for oil and gas leases, are charged to expense as incurred. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the unit-of-production DD&A rate. A gain or loss is recognized for all other sales of proved properties and is classified in other operating revenues. Maintenance and repairs are charged to expense, and renewals and betterments are capitalized to the appropriate property and equipment accounts.

Unevaluated oil and gas property costs are transferred to proved oil and gas properties if the properties are subsequently determined to be productive. Proceeds from sales of partial interests in unproved leases are accounted for as a recovery of cost without recognizing any gain until all costs are recovered. Unevaluated oil and gas properties are assessed periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks or future plans to develop acreage.

We review our proved oil and gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the expected undiscounted future cash flows of our oil and gas properties and compare such undiscounted future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, recent sales prices of comparable properties, the present value of estimated future cash flows, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected.

The provision for DD&A of oil and gas properties is calculated on a field-by-field basis using the unit-of-production method. Natural gas is converted to barrel equivalents, BOE, at the rate of six Mcf to one barrel of oil. Estimated future dismantlement, restoration and abandonment costs, which are net of estimated salvage values, are taken into consideration.

Asset Retirement Obligations

The estimated fair value of the future costs associated with dismantlement, abandonment and restoration of oil and gas properties is recorded generally upon acquisition or completion of a well. The net estimated costs are discounted to present values using a credit-adjusted, risk-free rate over the estimated economic life of the oil and gas properties. Such costs are capitalized as part of the related asset. The asset is depleted on the units-of-production method on a field-by-field basis. The associated liability is classified in current and long-term liabilities in the Consolidated Balance Sheets. The liability is periodically adjusted to reflect (1) new liabilities incurred, (2) liabilities settled during the period, (3) accretion expense and (4) revisions to estimated future cash flow requirements. The accretion expense is recorded as a component of depreciation, depletion and amortization expense in the Consolidated Statements of Operations.

Stock-based Compensation

We have not granted any stock options or warrants during the years ended December 31, 2010 and 2011 or for the six-months ended June 30, 2012 and no options or warrants were outstanding at any time during these years. We have issued shares of common stock for services performed by officers, directors and unrelated parties during 2010, 2011 and the first six-months of 2012. We have recorded these transactions based on the value of the services or the value of the common stock, whichever is more readily determinable.

Results of Operations for the Years Ended December 31, 2010 and 2011

The following discussion should be read in conjunction with the consolidated financial statements included elsewhere in this prospectus.

Oil and Gas Producing Activities

In the third quarter of 2011 we completed an acquisition of oil and gas properties in Wyoming, Colorado, Kansas and Montana. Prior to this date, we did not have any oil and gas producing activities. Presented below is a summary of our oil and gas operations for the period from July 29, 2011 through December 31, 2011 (the “Five-Month Period”):


Oil Sales	$	783,491
Natural Gas Sales		221,658

Total Revenue		1,005,149
Production Taxes		(89,109	)
Lease Operating Expense		(449,854	)
Depreciation, depletion, amortization and accretion		(310,308	)

Net	$	155,878

Net barrels of oil sold		9,990
Net mcf of gas sold		38,477
Average price for oil	$	78.43

Average price for gas	$	5.76

Lease operating expense per BOE	$	27.43

DD&A per BOE	$	18.92

Our oil sales are primarily attributable to our properties in Kansas and Wyoming. The average oil price for the 2011 period was $78.43 per barrel but ranged from $73.39 in September to a high of $86.19 in November. Our average gas price, including proceeds from sales of natural gas liquids, amounted to $5.76 per Mcf for the 2011 period but ranged from $4.84 per Mcf in December to $6.65 per Mcf in August.

Production taxes were approximately 9% of our oil and gas sales for the 2011 period. Lease Operating Expense averaged $27.43 per BOE whereby six Mcf of gas are equal to one barrel of oil. Many of the producing wells we purchased have been producing for a decade or longer and the cost of workovers and normal maintenance are charged to expense in the period the costs are incurred.

Under successful efforts accounting, DD&A expense is computed separately for each producing field based on geologic and reservoir delineation. The capital expenditures for proved properties for each field compared to the proved reserves corresponding to each producing field determine a weighted average DD&A rate for current production. Future DD&A rates will be adjusted to reflect future capital expenditures and proved reserve changes in specific areas.

Gas Gathering Activities

We have owned and operated a natural gas gathering system (pipeline and compressor station) in the Powder River Basin of Wyoming since 2006. We had $167,625 of revenues for the year ended December 31, 2010 and $45,638 for the year ended December 31, 2011. The decrease in revenue in 2011 of $121,987, or 72.8%, was primarily due to low natural gas prices which resulted in all wells in the field being shut-in since June 2011.

Presented below is a summary of operating costs for the years ended December 31, 2010 and 2011:


	2010		2011		Percent Change
Related party- cost of production	$	104,606	$	30,815		-70.5	%

Unrelated parties:
Compressor rental		131,492		46,961		-64.3	%
Pumper costs		43,300		15,000		-65.4	%
Transportation		25,497		8,042		-68.4	%
Property taxes		6,856		5,561		-18.9	%
Land rent, utilities, repairs and other		15,840		16,856		6.4	%

Total unrelated party costs		222,985		92,420		-58.6	%

Total	$	327,591	$	123,235		-62.4	%

The reductions in related party cost of production, and unrelated party expenses for compressor rental, pumper costs and transportation during 2011 were primarily due to the decision to shut-in the coal bed methane properties in June 2011 which allowed us to substantially eliminate these costs for the remainder of 2011. Depreciation expense related to the gas gathering system was approximately $44,200 for both 2010 and 2011.

In the third quarter of 2011, we acquired the entire field of coal bed methane wells that process gas through our system as part of our property acquisition discussed above. While these wells are not economic at current prices being received for natural gas related to the production capability from the existing geologic formation, we have geologic and engineering data that suggest substantial gas reserves exist on these properties by drilling new wells and/or recompleting the existing wells to several new geologic formations. We expect to further evaluate these properties and, if warranted, seek to execute our development plans within the next three years to seek to exploit the value of the properties and the gas gathering system. Any such developments will be dependent on available capital, which we do not have at this time. As of December 31, 2011, the capitalized cost of the coal bed methane leases is $287,728 and the net capitalized cost of the gas gathering system is $233,526.

General and Administrative

Presented below is a summary of general and administrative expenses for the years ended December 31, 2010 and 2011:


	2010		2011
Director fees	$	100,450	$	120,000
Investor relations		138,889		309,703
Acquisition investigation and due diligence		22,050		514,579
Legal, auditing and transfer agent		30,974		198,873
Accounting, financial reporting and rent- related party		53,000		83,802
Consulting fees:
Related parties		122,500		167,500
Unrelated parties		238,700		297,950
Office, travel and other		16,546		46,441
Depreciation		—		570

Total general and administrative expenses	$	723,109	$	1,739,418

General and administrative expenses increased by $1,016,309 in 2011 compared to 2010 or 240.5%. This increase was primarily due to increases in acquisition investigation and due diligence costs of $492,529; investor relations of $170,814; legal, auditing and transfer agent costs of $167,899; and consulting fees of $104,250.

The increase in acquisition investigation and due diligence costs of $492,529 was primarily due to a charge of $457,500 related to an April 2011 agreement with a consultant who assisted us with the negotiation of the July 29, 2011 acquisition of oil and gas properties. The increase in investor relations costs of $170,814 was due to additional investment banking, market information and shareholder communication services in 2011. The increase in legal, auditing and transfer agent costs of $167,899 was due to legal and auditing services that were required because of an increase in our filings with the SEC in 2011, and a substantial increase in the complexity of our business due to the acquisition of oil and gas properties and the issuance of convertible preferred stock. The increase in consulting fees of $104,250 was due to additional administrative support that was necessary due to the substantial increase in the scope of our operations.

Gain on sale of oil and gas properties

One of the properties purchased in 2011 was sold to an unrelated purchaser in 2011. Pursuant to the amended agreement for our purchase of the properties, we received $5,101,047 of the net proceeds from this sale which resulted in a gain of $2,479,934. This gain on sale is included in non-operating income for the year ended December 31, 2011. We applied the proceeds to the payments due under the property purchase. We expect to periodically evaluate our portfolio of properties and sell additional properties if we believe a sale can be completed on terms that provide attractive returns to us.

Gain on extinguishment of debt

We recognized gains on debt extinguishments of $121,870 for 2010 and $111,690 for 2011. The gain in 2011 was due to expiration of the statute of limitations related to previous obligations of our inactive subsidiary which resulted in the elimination of the liability and a credit to income.

Interest expense

Interest expense increased from $47,191 in 2010 to $391,606 in 2011, an increase of $344,415. This increase was due to a substantial increase in borrowings in 2011 needed to fund operations and the purchase of oil and gas properties. Additionally, the seller of the oil and gas properties provided interim financing for $10.1 million of the purchase price for a period of two months which resulted in interest expense of approximately $121,000 in 2011.

Income (loss) from operations

Loss from operations for the year ended December 31, 2011 was $1,705,356 compared to a loss from operations of $927,304 for the year ended December 31, 2010. The increase in loss from operations of $778,052 included the items discussed above relating to the oil and natural gas operations and other operating costs.

Results of Operations for the Six-Months Ended June 30, 2011 and 2012

To date, inflation has not had a material impact on our operations. Presented below is a discussion of our results of operations for the six-months ended June 30, 2011 and 2012.

Oil and Gas Producing Activities

During the third quarter of 2011, we entered into a purchase and sale agreement which resulted in our acquisition of producing oil and gas properties in Wyoming, Colorado, Kansas and Montana. Accordingly, for the first six-months of 2011 we did not have any oil and gas producing activities. Presented below is a summary of our oil and gas operations for the six-months ended June 30, 2012:


Oil sales	$	861,319
Natural gas sales		174,076

Total Revenue		1,035,395
Production taxes		(84,326	)
Lease operating expense		(401,653	)
Depreciation, depletion, amortization and accretion (“DD&A)		(336,837	)

Net	$	212,579

Net barrels of oil sold		10,565
Net mcf of gas sold		43,320
Net Barrels of Oil Equivalent (“BOE”) sold		17,785
Average price for oil	$	81.53

Average price for gas	$	4.02

Lease operating expense per BOE	$	22.58

DD&A per BOE	$	18.94

Our oil sales were primarily attributable to our properties in Kansas and Wyoming. The average oil price for the first six-months of 2012 was $81.53 per barrel but ranged from a high of $91.08 in February to a low of $67.62 in June. Our average natural gas price, including proceeds from sales of natural gas liquids, amounted to $4.02 per Mcf for the first six-months of 2012 but ranged from a high of $4.81 per Mcf for January to a low of $2.82 per Mcf in May .

Production taxes were approximately 8.1% of our oil and gas sales for the first six-months of 2012. Lease operating expense averaged $22.58 per BOE whereby six Mcf of natural gas are equal to one barrel of oil. Many of the wells included in our acquisition have been producing for more than a decade and consequently repairs are needed to maintain production levels.

Under successful efforts accounting, DD&A expense is separately computed for each producing field based on geologic and reservoir delineation. The capital expenditures for proved properties for each field compared to the proved reserves corresponding to each producing field determine a weighted average DD&A rate for current production. Future DD&A rates will be adjusted to reflect future capital expenditures and proved reserve changes in specific areas .

During the first quarter of 2012, we sold one of our properties with a 100% working interest in a producing oil and gas well, which resulted in gross proceeds of approximately $1,109,000. This property was sold to an unrelated purchaser and pursuant to our amended purchase agreement entered into during the third quarter of 2011, we were required to pay the related party sellers approximately $283,000 of the proceeds due to their contingent interest and, as a result our net proceeds were $826,000. After deducting the net book value of the property of $309,000, plus the asset retirement obligation assumed by the unrelated purchaser of $16,000, we recognized a gain of approximately $533,000, which is included in operating revenues in the accompanying unaudited consolidated statements of operations. We expect to periodically evaluate our portfolio of properties and sell additional properties if we believe a sale can be completed on terms that provide attractive returns.

Gas Gathering Activities

We have owned and operated a natural gas gathering system (pipeline and compressor station) for coal bed methane properties in the Powder River Basin of Wyoming since 2006. We had $45,639 of revenues for the first six-months of 2011 compared to no revenues for the first six-months of 2012. Due to a reduction in natural gas prices, all wells in the field have been shut-in since June 2011.

Presented below is a summary of operating costs for the six-months ended June 30, 2011 and 2012:


					Percent
	2011		2012		Change
Related party- cost of production	$	30,815	$	—		(100.0	%)

Unrelated parties:
Compressor rental		46,961		—		(100.0	%)
Pumper costs		15,000		—		(100.0	%)
Transportation		8,042		—		(100.0	%)
Property taxes		3,236		2,785		(13.9	%)
Land rent, utilities, repairs and other		7,319		4,535		(38.0	%)

Total unrelated party costs		80,558		7,320		(90.9	%)

Total	$	111,373	$	7,320		(93.4	%)

The reductions in related party cost of production, and unrelated party expenses for compressor rental, pumper costs and transportation during 2012 were primarily due to the decision to shut-in the coal bed methane properties in June 2011 which allowed us to substantially eliminate these costs for the remainder of 2011 and the first six-months of 2012. Depreciation expense related to the gas gathering system was $22,110 for the first six-months of both 2011 and 2012.

In July 2011, we acquired the entire field of coal bed methane wells as part of our $11 million acquisition. While these wells are not economic at current prices being received for natural gas related to the production capability from the existing geologic formation, we have geologic and engineering data that suggest substantial gas reserves exist on these properties by drilling new wells and/or recompleting the existing wells to several new geologic formations. We expect to further evaluate these properties and, if warranted, execute our development plans to exploit the value of the properties and the gas gathering system.

General and Administrative

Presented below is a summary of general and administrative expenses for the six-months ended June 30, 2011 and 2012:


	2011		2012		Change
Director fees	$	60,000	$	60,000	$	—
Investor relations		225,322		130,031		(95,291	)
Acquisition investigation and due diligence		500,478		—		(500,478	)
Legal, auditing and transfer agent		85,969		77,642		(8,327	)
Consulting and executive services :
Related parties		112,750		316,500		203,750
Unrelated parties		161,852		76,504		(85,348	)
Other administrative expenses		25,695		42,795		17,100
Depreciation		—		285		285

Total general and administrative expenses	$	1,172,066	$	703,757	$	(468,309	)

General and administrative expenses decreased by $468,309 for the first six-months of 2012 compared to 2011, primarily due to decreases in acquisition investigation and due diligence costs of $500,478, investor relations of $95,291, and unrelated party consulting fees of $85,348. These decreases were offset by increases in consulting and executive services with related parties of $203,750, and other administrative costs of $17,100 .

The decrease in acquisition investigation and due diligence costs of $500,478 was primarily due to a charge of $457,500 under a consulting agreement entered into during the second quarter of 2011 to evaluate the oil and gas properties that were ultimately acquired in the third quarter of 2011. We did not evaluate any significant acquisitions during the first six-months of 2012 and, accordingly, no costs were incurred. The decrease in consulting fees paid to unrelated parties of $85,348 was primarily attributable to a reduction in consulting fees related to capital structure and financings in the first six-months of 2012. The decrease in investor relations costs of $95,291 was due to substantial activities related to investment banking, market information and shareholder communication services that were performed in the first six-months of 2011 in preparation for the acquisition that was consummated in the third quarter of 2011. The increase in consulting and executive services with related parties of $203,750 was primarily due to the following:

•

Effective October 1, 2011, the Company entered into an Operator Agreement with DNR which resulted in a charge of $90,000 for the first six-months of 2012 to provide executive level operations expertise for our existing and prospective oil and properties. The total charge under the Operator Agreement was $138,000 for the first six-months of 2012, of which $48,000 was allocated to lease operating expense and $90,000 was allocated to general and administrative expenses. DNR is an affiliate of Charles B. Davis, an executive officer and director of the Company.

•

Effective January 1, 2012, the Board of Directors agreed to pay fees for executive, administrative and operational services in the aggregate amount of $15,000 per month to three individuals who are directors and/or stockholders of the Company. These fees are payable in shares of the Company’s common stock based on the closing price on the last day of the month for which the services are performed. For the six-months ended June 30, 2012, the Company incurred aggregate fees of $90,000 under this arrangement.

•

During the first six-months of 2012, the Company amended a consulting agreement that provided for a wide range of financial, regulatory and corporate structure services. As a result of this amendment the Company paid $50,000 in cash and issued 85,000 shares of commons stock with a fair market value of $50,000.

Income (loss) from operations

Income from operations for the first six-months of 2012 was $12,440 compared to a loss of $1,259,910 for the first six-months of 2011. The improvement of $1,272,350 was primarily due to the gain on sale of oil and gas properties of $533,048, the reduction in acquisition investigation and due diligence of $500,478, as well as the other items discussed above relating to the oil and natural gas operations, gas gathering activities, and general and administrative expenses.

Interest Expense

Interest expense decreased from $34,442 in the first six-months of 2011 to $32,401 in the first six-months of 2012, a decrease of $2,041. This decrease was due to lower weighted average borrowings in the first six months of 2012 and was partially offset by penalty interest incurred on a loan that was paid off in the first quarter of 2012.

Liquidity and Capital Resources

We had a working capital deficit as of June 30, 2012 of approximately $1,455,000, compared to a working capital deficit of $1,667,440 at December 31, 2011. We generated positive operating cash flow of approximately $75,000 for the first six-months of 2012 compared to negative operating cash flow of approximately $459,000 for the first six-months of 2011. The net increase in operating cash flow of $534,000 was primarily due to a $1,274,000 improvement from a net loss of $1,294,000 in the first six-months of 2011 to a net loss of $20,000 in the first six-months of 2012, and an increase in depreciation, depletion, amortization and accretion of $333,000. These improvements were partially offset by a $533,000 gain attributable to investing activities, a reduction in common stock issued for services of $487,000, and changes in working capital of $68,000.

For the first six-months of 2011, our cash flows related to investing activities consisted solely of a $500,000 down payment for the acquisition of oil and gas properties that were acquired in the third quarter of 2011. For the first six-months of 2012, we generated net proceeds of approximately $826,000 from the sale of a 100% working interest in an oil and gas property. We realized a gain of approximately $533,000 on the sale of this property. The net proceeds from the sale of oil and gas properties were partially offset by capital expenditures of $646,000, of which approximately $598,000 was acquisition costs paid to a related party for the group of properties that we acquired in the third quarter of 2011.

For the first six-months of 2011, we had net borrowings of approximately $861,000 and we received proceeds from the sale of common stock of $103,500. These funds were needed to fund our operations as well as to make a $500,000 deposit on the oil and gas properties that were acquired in the third quarter of 2011. For the first six-months of 2012, our financing activities used net cash proceeds of $306,000, primarily due to the payment of $392,000 of dividends on our preferred stock in April 2012. During the first six-months of 2012, we also borrowed $400,000 and repaid borrowings of $265,000. The borrowings of $400,000 during the first six-months of 2012 provide for interest at 12.0% and a due date in March 2013. During the first six-months of 2012, we also paid $50,000 of offering costs that were incurred in connection with our 2011 private placement of preferred stock.

As of June 30, 2012, we had cash and equivalents of approximately $168,000. Based on the current prices received from the sale of our oil and natural gas, the cash flows will likely not be adequate to cover all of our operating, general, administrative and interest costs. We do not have any material commitments for capital expenditures. However, if we can obtain adequate financing we expect to incur up to $964,000 during the second half of 2012 for development drilling on our existing oil and gas properties. We also expect to evaluate acquisitions that are consistent with our business objective of acquiring interests in traditional oil and gas ventures, and seeking properties that offer profit potential from overlooked and by-passed reserves of oil and natural gas.

In order to execute our development drilling plans and to acquire additional interests in oil and gas properties that meet our objectives, we need to obtain significant additional financing. From the time we acquired our existing properties in the third quarter of 2011, we have sold our interests in some of those properties, which resulted in aggregate net proceeds from two sales of $5,927,000, which was used to repay acquisition indebtedness. We intend to only sell properties that can be liquidated for a premium and there can be no assurance that we will continue to generate any proceeds from the sale of our properties.

We are currently in preliminary discussions with lenders that have expressed an interest in providing a line of credit that would be secured by our oil and gas properties. There is no assurance that we will be successful in attracting a lender or that the amount of any financing will be sufficient to execute our business plan for 2012. On September 29, 2012, we obtained interim financing of $455,000 under a note agreement that provides for interest at an annual rate of 12% with unpaid principal and interest due on March 29, 2013. We agreed to assign 75% of the operating income from our oil and gas properties and any lease or well sale or any other asset sales to the Note Holder to secure this debt. The Note Holder is 100% owned by a consultant and shareholder of the Company. We also paid a loan fee of $2,700 and prepaid interest of $27,300 on the Note, resulting in net proceeds of $420,000. On September 11, 2012 the Board of Directors declared the 15% dividend on the Series A-1 preferred stock which was paid in cash on October 1, 2012. The net proceeds from this loan were utilized to fund the dividend payment in the approximate amount of $392,000.

If oil and gas prices decrease materially from current levels and additional debt or equity funding is unavailable on acceptable terms, or at all, our strategy would include some or all of the following: (i) defer development drilling on our existing properties, (ii) forego additional oil and gas property acquisitions, (iii) shut-in any marginal or uneconomic wells, (iv) attempt to negotiate the issuance of common stock in exchange for services, (v) pay preferred stock dividends through the issuance of our common stock, and (vi) review and implement other opportunities to reduce general, administrative and operating expenses.

Contractual Obligations and Commercial Commitments

As of June 30, 2012, we have future minimum lease payments of approximately $8,000. This amount is payable during the years ending June 30, 2013, 2014, 2015, 2016, 2017 and after 2017 in the amounts of $2,000, $1,000, $1,000, $1,000, $1,000, and $2,000, respectively.

Off-Balance Sheet Arrangements

In connection with the related party acquisition of oil and gas properties in the third quarter of 2011, we acquired interests in certain geologic zones of the properties. For a period of ten years after the closing date, the Colorado and Kansas properties provide for additional consideration that is payable to Sellers based on increases in Nymex prices for oil and natural gas, without regard to changes in the Company’s oil and natural gas reserves (referred to as the “Price Increase Factor”). If Nymex thresholds of $90, $100, $110, $125 and $150 per barrel of oil are exceeded for periods of 61 days or more, incremental purchase consideration of $250,000, $250,000, $500,000, $500,000 and $2,000,000, respectively, will be payable to Sellers. Similarly, if Nymex thresholds of $5.00, $6.00, $7.50, $10.00 and $12.00 per MMbtu of natural gas are exceeded for periods of 61 days or more, incremental purchase consideration of $50,000, $50,000, $150,000, $250,000 and $250,000, respectively, will be payable to Sellers.

The Colorado and Kansas properties also provide for additional consideration that is payable to Sellers if reserves classified as “possible” are converted to “proved producing reserves” through drilling or recompletion activities over a period of ten years after the closing date (referred to as the “Possible Reserve Factor”). For such increases in oil reserves, the Sellers are entitled to additional consideration of $250,000 for each increase of 20,000 net barrels; and for such increases in natural gas reserves, the Sellers are entitled to additional consideration of $150,000 for each increase of 150,000 mcf of natural gas.

The Possible Reserve Factor also requires a multiplier effect from 1 to 5 depending on the Price Increase Factor that is effective when the proved producing reserves are obtained. For example, the Possible Reserve Factor consideration would be multiplied by 2 if the oil Price Increase Factor of $100 is in effect when the proved producing reserves are confirmed. Similarly, the Possible Reserve Factor consideration would be multiplied by 2 if a natural gas Price Increase Factor of $6.00 per MMbtu is in effect when the proved producing natural gas reserves are confirmed. The maximum increase in purchase price for the Kansas and Colorado properties is limited to $5 million.

Additional consideration is also payable for the properties located in Wyoming to the extent that the Company increases proved producing reserves through future drilling or recompletion activities in formations that are not producing as of the closing date under the Possible Reserve Factor. Similar to the properties in Colorado and Kansas, the Possible Reserve Factor will be multiplied by a factor of 1 to 5 depending on the Price Increase Factor that is effective when the proved producing reserves are obtained.

Furthermore, if the Company sells any of the properties in Wyoming, the Sellers have retained an interest of 70% in the net sales proceeds (after the Company receives a recovery of 125% of the original agreed-upon allocation).

The maximum increase in purchase price (including Sellers retained interest of 70% for the Wyoming properties discussed in the preceding paragraph) for all properties in all states is limited to $25 million. Due to the sale of the Separate Interests in August 2011, accrual of $500,000 due to a sustained increase in oil prices over $90 and $100 per barrel, and the sale of a second property in February 2012, the maximum future consideration has been reduced by approximately $5.2 million to $19.8 million as of June 30, 2012 .

New Accounting Pronouncements

In May 2011, the FASB issued new fair value measurement authoritative accounting guidance clarifying the application of fair value measurement and disclosure requirements and changes particular principles or requirements for measuring fair value. This authoritative accounting guidance is effective for interim and annual periods beginning after December 15, 2011. Based on the Company’s current operations and structure, the adoption of this standard did not have an impact on the Company’s 2012 financial statements.

In June 2011, the FASB issued new authoritative accounting guidance that states an entity that reports items of other comprehensive income has the option to present the components of net income and comprehensive income in either one continuous financial statement, or two consecutive financial statements, including reclassification adjustments. In December 2011, the FASB issued new authoritative accounting guidance which effectively deferred the requirement to present the reclassification adjustments on the face of the financial statements. This authoritative accounting guidance is effective for interim and annual periods beginning after December 15, 2011. Based on the Company’s current operations and structure, the adoption of this standard did not have an impact on the Company’s 2012 financial statements.

Other accounting standards that have been issued or proposed by the FASB, or other standards-setting bodies, that do not require adoption until a future date are not expected to have a material impact on the financial statements upon adoption.

Controls and Procedures

As of June 30, 2012, our Chief Executive Officer and Chief Financial Officer (the “Certifying Officers”) conducted evaluations of our disclosure controls and procedures. As defined under Sections 13a-15(e) and 15d-15(e) of the Exchange Act, the term “disclosure controls and procedures” means controls and other procedures of an issuer that are designed to ensure that information required to be disclosed by the issuer in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer’s management, including the Certifying Officers, to allow timely decisions regarding required disclosure. Based on this evaluation, the Certifying Officers have concluded that our disclosure controls and procedures were not effective to ensure that material information is recorded, processed, summarized and reported by our management on a timely basis in order to comply with our disclosure obligations under the Exchange Act and the rules and regulations promulgated thereunder. As discussed in our annual report on Form 10-K for the year ended December 31, 2011, the ineffectiveness of our disclosure controls and procedures is due primarily to (i) our Board of Directors does not currently have any independent members that qualify as an audit committee financial expert, (ii) we have not developed and effectively communicated our accounting policies and procedures, and (iii) our controls over financial statement disclosures were determined to be ineffective.

Further, there were no changes in our internal control over financial reporting during the second fiscal quarter that has materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

MANAGEMENT

Identify Directors and Executive Officers

The directors named below were elected for one-year terms. Officers hold their positions at the discretion of the Board of Directors absent any employment agreements, none of which currently exist or are contemplated.

The names, addresses and ages of each of our directors and executive officers and the positions and offices held by them, which director positions are for a period of one year, are:


Name and Address	Age	First Became Officer and/or Director	Position(s)
Donald W. Prosser 7260 Osceola Street Westminster, CO 80030	61	September 2003	Chairman and Chief Executive Officer

John R. Herzog 7260 Osceola Street Westminster, CO 80030	68	September 2003	Director and Acting Chief Financial Officer

Charles B. Davis 7260 Osceola Street Westminster, CO 80030	55	October 2007	Director and Chief Operating Officer

Charles L. Gamber 7260 Osceola Street Westminster, CO 80030	61	September 2003	Director and Secretary

William W. Stewart 7260 Osceola Street Westminster, CO 80030	50	December 2001	Director and Assistant Secretary

Donald W. Prosser

Mr. Prosser is a Director and member of our Compensation and Audit Committees. He has been designated as the Company’s Audit Committee Financial Expert. Mr. Prosser is a practicing certified public accountant, specializing in tax and securities accounting, and has represented a number of companies serving in the capacity of CPA, member of boards of directors, and as Chief Financial Officer. Mr. Prosser brings to the Company his great depth of expertise in tax and securities compliance and accounting, corporate finance transactions and turn-around.

From 1997 to 1999, Mr. Prosser served as CFO and Director for Chartwell International, Inc, a publicly traded company which filed reports under the Exchange Act which published high school athletic information and provided athletic recruiting services. From 1999 to 2000, he served as CFO and Director for Anything Internet, Inc. and from 2000 to 2001, served as CFO and Director for its successor, Inform Worldwide Holdings, Inc., which is a publicly traded company which filed reports under the Exchange Act. From 2001 to 2002, Mr. Prosser served as CFO and Director for Net Commerce, Inc, a public company selling internet services. From November 2002 through June 2008, Mr. Prosser served as CFO of VCG Holding Corp., a publicly traded company which filed reports under the Exchange Act and engaged in the business of acquiring, owning and operating nightclubs. His accounting firm performs accounting service for VCG Holding Corp. From July 2008 through August 2009 Mr. Prosser was chief financial officer of IPtimize, Inc., a provider of broadband and data services that filed a petition under federal bankruptcy laws in October 2009. Since July 2012 he has served as a director of MusclePhar Corporation, a publicly traded company that has a class of securities registered under the Exchange Act.

Mr. Prosser has been a certified public accountant since 1975, and is licensed in the state of Colorado. Mr. Prosser attended the University of Colorado from 1970 to 1971 and Western State College of Colorado from 1972 to 1975, where he earned a Bachelor’s degree in both accounting and history (1973) and a Masters degree in accounting – income taxation (1975).

John R. Herzog

Mr. Herzog serves as an independent Director, and as a member of the Company’s Audit, Nominating and Compensation Committees. From 1998 to 2000, Mr. Herzog served as Director of Billing Services for Eglobe, Inc., where he managed daily operations, conversion of the billing system. From 2000 to 2001, he served as director of IT for Anything Internet, Inc., a publicly traded company which filed reports under the Exchange Act. Since 2001, Mr. Herzog has been President of Business Information Systems, Inc., developing applications, consulting on software development, business systems, and programming. Mr. Herzog also served as a Director of Net Commerce, Inc., a public company, from 2001 to 2002. Mr. Herzog graduated from Drexel University in 1967 with a degree in Electrical Engineering, and in 1970 with a Master’s degree in Biomedical Engineering. He received a Doctorate from Temple University in 1976.

Charles B. Davis

Mr. Davis joined Arête’s Board of Directors in 2006, and serves as a member of the Company’s Nominating and Compensation Committees. From January 1981 to June 1983, Mr. Davis was Operations Manager for Keba Oil and Gas Co. where he was responsible for drilling, completion and producing operations. From July 1983 to April 1986, Mr. Davis was Vice-President of operations for Private Oil Industries. From April 1986 until August 1988, Mr. Davis did consulting work related to well site operations. Since August 1988 Mr. Davis has worked for DNR Oil & Gas Inc., as president, overseeing the day to day operations for 150 to 200 wells, and involved in exploration activities. Mr. Davis graduated from the University of Wyoming with a Bachelor of Science Degree in Engineering.

Charles L. Gamber

Mr. Gamber joined Arête’s Board of Directors in September 2003. He serves as an independent director, and is a member of our Nominating, Audit, and Compensation Committees. Mr. Gamber is the owner of Charles L. Gamber, Inc. dba Capital Resource Management LLC and works as a consultant creating business opportunities and relationships with strategic partners and business organizations. He is also the Director of Business Development for MedCenterNetwork. He has over 35 years of sales, customer service and marketing experience. Mr. Gamber started Charles L Gamber, Inc., in 2003. Mr. Gamber received a bachelor’s degree in Business Administration with minors in Accounting and Economics from Western State College of Colorado in 1973.

William W. Stewart

From December, 2001 until August, 2002, Mr. Stewart ran the operations and directed the business plan of Eagle Capital Funding Corp. (Eagle Capital) to pursue capital funding projects. In addition to serving as an outside director, he serves as a member of the Company’s Nominating and Compensation Committees. Mr. Stewart worked in the brokerage industry as an NASD licensed registered representative from 1986 to 1994. Mr. Stewart started his career with Boettcher and Company of Denver, Colorado and left the Principal Financial Group of Denver, Colorado in 1994 to open his own small-cap investment firm, S.W. Gordon Capital, Inc., where he has been its president since 1994 to the present. Mr. Stewart formerly served as CEO and is an owner of Larimer County Sports, LLC, a Colorado limited liability company, which owns the Colorado Eagles Hockey Club a minor league professional hockey franchise in northern Colorado. He has been President of Wenatche Sports Partners, LLC, owner of a minor league hockey team, since 2008. Mr. Stewart attended the University of Denver on a full athletic scholarship where he played hockey from 1979 to 1983 as right wing and served as assistant captain during his senior year. Mr. Stewart graduated with a BS, Business Administration from the University of Denver in 1983, with honors as a Student Athlete.

Board Committees

Our Board of Directors oversees the business affairs of the Company and monitors the performance of our management. The Board of Directors has designated three standing committees: the Audit Committee, the Nominating Committee, and the Compensation Committee. The Board of Directors met thirteen times during the year 2011.

Audit Committee (Messrs. Gamber, Herzog and Prosser)

The Audit Committee’s primary responsibilities are to monitor our financial reporting process and internal control system, to monitor the audit processes of our independent auditors, and internal financial management; and to provide an open avenue of communication among our independent auditors, financial and senior management and the Board. The Audit Committee reviews its charter annually and updates it as appropriate. The Committee met four times during the year 2011.

Audit Committee Financial Expert

The Board has determined that Mr. Prosser is an audit committee financial expert; however, he is not independent within the meaning of Regulation S-K.

Nominating Committee (Messrs. Davis, Herzog and Stewart)

The Nominating Committee was also established in 2003. It identifies candidates for future Board membership and proposes criteria for Board candidates and candidates to fill Board vacancies, as well as a slate of directors for election by the shareholders at each annual meeting. The Committee annually assesses and reports to the Board on the Board Committee performance and effectiveness; reviews and makes recommendations to the Board concerning the composition, size and structure of the Board and its committees; and annually reviews and reports to the Board on director compensation and benefits matters. The Nominating Committee met one time during the year 2011.

Compensation Committee.

While the Company established a Compensation Committee in 2003, our full Board currently administers compensation matters. As we expand our operations and compensation policies, we intend to appoint members to the committee. Upon reinstatement of the Committee, it will administer our incentive plans, sets policies that govern executives’ annual compensation and long-term incentives, and reviews management performance, compensation, development and succession.

Compliance with Section 16(a) of the Exchange Act.

The Company files reports under Section l5 (d) of the Exchange Act; accordingly, directors, executive officers and 10% shareholders are not required to make filings under Section 16 of the Exchange Act.

CODE OF BUSINESS CONDUCT AND ETHICS

Our corporate philosophy is that good ethics and good business conduct go hand in hand. Our business standards provide a general framework of values and obligations that should be adhered to at all times. Corporate standards guide our professional conduct in regard to actions, words, sense of fairness, honesty and integrity. The Company is required to comply with laws in all jurisdictions, and our Code of Business Conduct and Ethics, which we refer to as the Code, supports and reflects our statutory compliance with such laws. The Code applies to our principal executive officer, principal financial officer, principal accounting officer or controller, and persons performing similar functions.

EXECUTIVE COMPENSATION

We do not currently have any full time or part time employees. Our three executive officers, who are also directors, did not receive any salary or other compensatory benefits during 2011 or 2010 in their capacity as officers. During 2011 and 2010, we used independent contractors, consultants, attorneys and accountants as necessary, to complement services for operations and regulatory filings.

We paid Donald W. Prosser, P.C. CPA, $90,000 (2011) and $50,000 (2010) for accounting and regulatory filing services. Mr. Prosser is our Chief Executive Officer and Director. We also paid Charles Davis $15,000 in 2011 for providing us with management services relating to our oil and gas properties. See also “Certain Relationships and Related Transactions” beginning on page 38 for further information regarding certain transactions with our officers.

Equity Awards

We do not maintain any equity award plans. Accordingly, there were no stock grants, options or other equity awards to our two executive officers in their capacity as officers.

Compensation of Directors.

The following table discloses the cash, equity awards and other compensation earned, paid or awarded, as the case may be, to each of our non-employee Directors during the fiscal year ended December 31, 2011.


Name	Fees Earned Or Paid in Cash ($)		Stock Awards ($) (1)		Option Awards ($)		All Other Compensation ($)		Total ($)
Charles Davis		—		24,000		—		—		24,000
Charles Gamber		—		24,000		—		—		24,000
John Herzog		—		24,000		—		—		24,000
Donald W. Prosser		—		24,000		—		—		24,000
William Stewart		—		24,000		—		—		24,000

(1)

Our Directors are paid a quarterly fee of $6,000 in shares of our common stock for their service on our Board of Directors. The fee is paid at the end of each calendar quarter and is calculated based on the closing price of our common stock as reported by the OTC Market as of the last day of each quarter.

Cash Compensation Paid to Directors

We currently do not pay any cash fees to our Directors for services provided in their capacity as Directors.

Equity Based Compensation Paid to Directors

As summarized in the table above, we pay each Director a $6,000 fee per calendar quarter for his service to our Board of Directors in shares of our common stock and the share numbers are calculated based on the closing price of our common stock as reported by the OTC market as of the last day of each quarter. Since we currently do not have any formal equity incentive plans, the stock fee is paid from our authorized shares. The offer and sale of shares issued in connection with the Directors’ fees are not registered with the SEC and are therefore “restricted securities” as that term is defined in Rule 144 of the SEC, and as such are subject to holding period requirements and other restrictions set forth in Rule 144.

Other

All Directors are reimbursed for their reasonable expenses incurred in connection with attending meetings.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Our officers and directors have advanced funds to pay for necessary expenses and costs of the Company. The following are the advances from the officers and directors:

As of December 31, 2010 and 2011, advances from related parties were unsecured and due on demand, as follows:


	2010		2011
Advances – Donald W. Prosser , CEO & Director(2)	$	220,000	$	20,000
Advances – Donald W. Prosser (3)		4,290		4,100
Advances – Donald W. Prosser (1)		215,000		—
Advances – Charles L. Gamber, Director (3)		4,966		—
Advances – William W. Stewart, Director (3)		20,219		20,219
Advances – William W. Stewart (2)		75,000		25,000
Advances – Charles B. Davis, Director (2)		125,000		—
Advances – Charles B. Davis (2)		40,000		40,000

Balances	$	704,475	$	109,319

(1)	Donald W. Prosser pledged 215,000 shares of his common stock to unrelated individuals in exchange for a loan to the Company of $215,000 due in May 2011. The loan was used for working capital.

(2)	$460,000 at December 31, 2010 and $85,000 at December 31, 2011 of the advances bear interest at 9.6% per annum.

(3)	$29,475 at December 31, 2010 and $24,319 at December 31, 2011 of the advances bear interest at 8.0% per annum.

We had related party payables of accrued interest to the officers and directors above of $37,121 at December 31, 2011.

In May 2011 we entered into a purchase and sale agreement, amended in July, 2011, for the purchase of certain oil and gas operating properties in Colorado, Kansas, Wyoming, and Montana with the Tucker Family Investments, LLLP, DNR and Tindall Operating Company, collectively, the “Sellers,” for the purchase of certain oil and gas operating properties in Colorado, Kansas, Wyoming, and Montana. In addition, the agreement included an operating agreement for the continued operations of the purchased properties by DNR. DNR is principally owned by Charles B. Davis, our Chief Operating Officer and one of our directors. The consideration for the purchase was determined by bargaining between management of the Company and Mr. Davis, and the Company used reports of independent engineering firms to analyze the purchase price. The base purchase price for the acquisition was $11,000,000. Potential additional purchase price payments are due under the following circumstances:

•

The Colorado and Kansas properties provide for additional consideration that is payable to Sellers if proved producing reserves are increased on these properties through drilling or recompletion activities over a period of ten years after the closing date. To the extent that oil reserves increase, the Sellers are entitled to additional consideration of $250,000 for each increase of 20,000 net barrels. Furthermore, to the extent that oil and gas prices increase, the Sellers are entitled to additional consideration as the targeted price thresholds are exceeded for periods of 61 days. The maximum increase in purchase price for the Kansas and Colorado properties is limited to a maximum of $5 million.

•

Notwithstanding the foregoing, the maximum increase in purchase price is limited to a maximum of $25 million. Due to sales of some of the properties to unrelated third parties and additional purchase price payable due because the $90 and $100 oil price thresholds were exceeded for 61 consecutive days, the maximum future consideration was reduced to approximately $19.8 million as of June 30, 2012.

We also entered into a contract operator agreement with DNR to operate all of the properties purchased pursuant to the purchase and sale agreement, as amended. Under the agreement, DNR:

•

operates, manages, and maintains the properties in accordance with past practices;

•

employs such personnel as may be reasonably necessary to operate the properties;

•

provides various accounting and governmental reporting functions;

•

purchases supplies, materials, tools and equipment associated with ownership and operation of the properties;

•

pays and performs all obligations of Arête which relate to the properties, including, without limitation, the payment of operating costs, vendor invoices and contractor invoices associated with ownership or operation of the properties; and

•

provides marketing, gas control and other similar services necessary to sell the oil and gas produced from the properties.

Under the contract operator agreement, we reimburse DNR for all third party costs and expenses, including without limitation, operating costs, capital expenditures, production taxes and producing, drilling and construction overhead charges billed by third party operators, incurred or borne by DNR and associated with the properties. In addition to the foregoing reimbursements, we pay DNR $23,000 per month for the performance of its services under the contract operator agreement.

On September 29, 2011, as part of our convertible preferred stock private placement of $5.2 million, Mr. Davis purchased 100 shares of our convertible preferred stock for $1 million.

SECURITY OWNERSHIP OF

CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Security Ownership of Certain Beneficial Owners and Management

The following table sets forth certain information regarding the beneficial ownership of the Company’s common stock as of October 16, 2012 by (i) each person known by the Company to beneficially own more than five percent of the outstanding shares of common stock, (ii) each current director and named executive officer of the Company and (iii) all executive officers and directors as a group. Except as indicated, the persons named in the table have sole voting and investment power with respect to all shares beneficially owned. Beneficial ownership is determined in accordance with the rules of the Securities and Exchange Commission and includes voting and investment power. In computing the number of shares beneficially owned by a person and the percentage ownership of that person, we have included convertible securities held by that person that are currently convertible or will become convertible within 60 days after October 16, 2012, but we have not included those shares for purposes of computing percentage ownership of any other person. The number and percentage of shares beneficially owned are based on 7,979,803 issued and outstanding as of October 16, 2012.


Title of Class	Name and Address of Beneficial Owner Directors and Executive Officers	Amount and Nature of Beneficial Ownership			Percent of Class
Common Stock	Charles Davis, Director/COO 7260 Osceola Street Westminster, Colorado 80030,	Direct	1,022,997	(1)		10.8	%
Common Stock	Charles L. Gamber, Director/Secretary 7260 Osceola Street Westminster, Colorado 80030,	Direct	103,522	(2)		1.3	%
Common Stock	John R.Herzog, Director/Acting CFO 7260 Osceola Street Westminster, Colorado 80030,	Direct	281,141	(2)		3.6	%
Common Stock	Donald W. Prosser, CEO/Chairman 7260 Osceola Street Westminster, Colorado 80030,	Direct	720,844	(3)		9.1	%
Common Stock	William W. Stewart, Director 7260 Osceola Street Westminster, Colorado 80030,	Direct	84,216	(2)		1.1	%

Common Stock	Directors and Officers as a Group (5 persons)	Total:	2,212,720			25.9	%

Common Stock	Herbert & Virginia Burridge 30722 Fairgreens Way Laguna Niguel, CA 92677	Direct	460,524			5.8	%
Common Stock	Burlingame Equity Investors Master Fund, L.P. One Market Plaza, Suite 3750 San Francisco, CA 94105	Direct	740,249	(4)		7.8	%

(1)	Includes 303,030 shares of common stock issuable upon conversion of 100 shares of convertible preferred stock and 30,113 shares accrued for services rendered.

(2)	Includes 13,113 shares accrued for services rendered.

(3)	Includes 30,113 shares accrued for services rendered.

(4)

Includes 557,576 shares of common stock issuable upon conversion of 184 shares of convertible preferred stock. The general partner of the named owner is Burlingame Asset Management, LLC. Blair Sanford is the managing member of the general partner and may be deemed to have beneficial ownership of these shares. He disclaims beneficial ownership of all shares held by the named owner.

Indemnification and Limitation on Liability of Directors

Our articles of incorporation, as amended, and bylaws provide that we must indemnify, to the fullest extent permitted by the laws of the State of Colorado, any of our directors, officers, employees or agents made or threatened to be made a party to a proceeding, by reason of the person serving or having served in a capacity as such, against judgments, penalties, fines, settlements and reasonable expenses incurred by the person in connection with the proceeding if certain standards are met.

The Colorado Business Corporation Act allows indemnification of directors, officers, employees and agents of a Colorado corporation against liabilities incurred in any proceeding in which an individual is made a party because he or she was a director, officer, employee or agent of the corporation if such person conducted himself in good faith and reasonably believed his actions were in, or not opposed to, the best interests of the corporation, and with respect to any criminal action or proceeding, had no reasonable cause to believe his conduct was unlawful. A person must be found to be entitled to indemnification under this statutory standard by

procedures designed to assure that disinterested members of the board of directors have approved indemnification or that, absent the ability to obtain sufficient numbers of disinterested directors, independent counsel or shareholders have approved the indemnification based on a finding that the person has met the standard. Indemnification is limited to reasonable expenses.

At present, there is no pending litigation or proceeding involving any of our directors, officers, employees or agents where indemnification will be required or permitted. Insofar as indemnification for liabilities arising under the Securities Act may be permitted to our directors, officers and controlling persons pursuant to the foregoing provisions, or otherwise, we have been advised that in the opinion of the SEC, such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable.

Our articles of incorporation limit the liability of our directors to the fullest extent permitted by law. Specifically, our directors will not be personally liable for monetary damages for breach of fiduciary duty as directors, except for:

•

any breach of the duty of loyalty to us or our shareholders;

•

acts or omissions not in good faith or that involved intentional misconduct or a knowing violation of law;

•

dividends or other distributions of corporate assets that are in contravention of certain statutory or contractual restrictions;

•

violations of certain laws; or

•

any transaction from which the director derives an improper personal benefit.

Liability under federal securities law is not limited by our articles of incorporation.

Shareholder Communications

We do not have a formal shareholder communications process. Shareholders are welcome to communicate with the Company by forwarding correspondence to Arête Industries Inc., Board of Directors, P.O. Box 141, Westminster, Colorado 80036, Attn.: Donald W. Prosser.

SELLING SHAREHOLDERS

On behalf of the selling shareholders, we have agreed to file a registration statement with the SEC covering the resale of our voting common stock which is issuable upon conversion of the shares of convertible preferred stock owned by each selling shareholder listed in the table below. We have also agreed to use our reasonable efforts to keep the registration statement effective and update the prospectus until the securities owned by the selling shareholders have been sold or may be sold without registration or prospectus delivery requirements under the Securities Act. We will pay the costs and fees of registering the shares, but the selling shareholders will pay any brokerage commissions, discounts or other expenses relating to the sale of the shares.

The registration statement which we have filed with the SEC, of which this prospectus forms a part, covers the resale of our common stock by the selling shareholders from time to time under Rule 415 of the Securities Act. Our agreement with the selling shareholders was entered into with the intention of providing those shareholders with additional liquidity in respect of their ownership of shares of our voting common stock. The selling shareholders may offer our securities covered under this prospectus for resale from time to time. The selling shareholders may also sell, transfer or otherwise dispose of all or a portion of our securities in transactions exempt from the registration requirements of the Securities Act. See “Plan of Distribution” beginning on page 43.

The table below presents information as of October 16, 2012 regarding the selling shareholders and the shares of our voting common stock that the selling shareholders may offer and sell from time to time under this prospectus. The table is prepared based on information supplied to us by those shareholders. Although we have assumed, for purposes of the table below, that the selling shareholders will sell all of the securities offered by this prospectus, because they may offer all or some of the securities in transactions covered by this prospectus or in another manner, no assurance can be given as to the actual number of shares that will be resold by the selling shareholders. Information covering the selling shareholders may change from time to time, and changed information will be presented in a supplement to this prospectus or an amendment to the registration statement if and when required. Except as described above, there are no agreements, arrangements or understandings with respect to resale of any of the securities covered by this prospectus.



	Number of				Number of
	Shares		Number of		Shares
	Beneficially		Shares		Beneficially		Percentage of Ownership
Name of	Owned Before		to be		Owned After		Before			After
Selling Shareholder	Offering		Offered(1)		Offering(2)		Offering			Offering(2)
Burlingame Equity Investors Master Fund, LP (3)		740,249		557,576		182,673		7.8	%		2.3	%
Burlingame Equity Investors II, LP (3)		65,812		48,485		17,327		0.7			0.2
Charles B. Davis		1,022,997		303,030		719,967		10.5			9.1
Michael J. Finney		150,940		15,152		135,788		1.6			1.9
T P Furlong		17,652		15,152		2,500		0.2			0
John H Rosasco		55,303		30,303		25,000		0.6			0.3
Lyon Oil Company LLC		35,302		30,302		5,000		0.4			0.1
Theodore Wahtell		30,303		30,303		0		0.3			0
William & Sara Kroske		17,576		7,576		10,000		0.2			0.1
Tucker Family Investments LLLP		92,749		75,758		16,991		1.0			0.2
Michael Geller		90,303		30,303		60,000		1.0			0.8
Nicholas Scheidt		443,530		303,030		140,500		3.8			0.7
Pete Haman		106,061		106,061		0		1.1			0
Marc Venjohn		30,303		30,303		0		0.3			0

TOTAL		2,899,079		1,583,333		1,315,746		29.7	%		15.6	%

(1)	Includes shares issuable upon exercise of outstanding preferred convertible stock.

(2)	Assumes that all of the shares offered in this prospectus are sold, of which there is no assurance.

(3)	The general partnership of this named owner is Burlingame Asset Management, LLC (“BAM”). The managing member of BAM is Blair Sanford, who may be deemed to have beneficial ownership of these shares. Mr. Sanford disclaims beneficial ownership of all of these shares.

None of the selling shareholders are United States broker-dealers, nor at the time of purchase did any of the selling shareholders have any agreements or understandings, directly or indirectly, with any persons to distribute the securities. Further, except for Charles B. Davis, none of the selling shareholders is an officer or director of the Company, except as a shareholder. Mr. Davis is our Chief Operating Officer and a Director.

PLAN OF DISTRIBUTION

The selling shareholders and their pledgees, donees, transferees or other successors in interest may offer the shares of our voting common stock and the shares underlying the convertible preferred stock from time to time after the date of this prospectus and will determine the time, manner and size of each sale in the over-the-counter market, on one or more exchanges, in privately negotiated transactions or otherwise, at market prices prevailing at the time of sale, at prices related to prevailing market prices, or at negotiated prices. The selling shareholders may negotiate, and may pay, broker or dealers commissions, discounts or concessions for their services. In effecting sales, brokers or dealers engaged by the selling shareholders may allow other brokers or dealers to participate. However, the selling shareholders and any brokers or dealers involved in the sale or resale of the shares may qualify as “underwriters” within the meaning of Section 2(a)(11) of the Securities Act. In addition, the brokers’ or dealers’ commissions, discounts or concessions may qualify as underwriters’ compensation under the Securities Act.

The methods by which the selling shareholders may sell the shares of our common stock include:

•

a block trade in which a broker or dealer so engaged will attempt to sell the shares as agent but may position and resell a portion of the block, as principal, in order to facilitate the transaction;

•

sales to a broker or dealer, as principal, in a market maker capacity or otherwise and resale by the broker or dealer for its account;

•

ordinary brokerage transactions and transactions in which a broker solicits purchases;

•

an exchange distribution in accordance with the rules of any stock exchange on which the securities are listed;

•

privately negotiated transactions;

•

short sales;

•

through the distribution of the securities by any selling shareholder to its partners, members or shareholders;

•

any combination of these methods of sale; or

•

any other legal method.

A selling shareholder may enter into hedging transactions with broker-dealers and the broker-dealers may engage in short sales of the securities in the course of hedging the positions they assume with that selling shareholder, including without limitation, in connection with distributions of the securities by those broker-dealers. A selling shareholder may enter into option or other transactions with broker-dealers that involve the delivery of the securities offered hereby to the broker-dealers, who may then resell or otherwise transfer those securities. A selling shareholder may also loan or pledge the securities offered hereby to a broker-dealer and the broker-dealer may sell the securities offered hereby so loaned or upon a default may sell or otherwise transfer the pledged securities offered hereby.

In addition to selling their shares under this prospectus, the selling shareholders may sell or transfer their shares by other methods not involving market makers or established trading markets, including directly by gift, distribution, or other transfer, or sell their shares under Rule 144 of the Securities Act rather than under this prospectus, if the transaction meets the requirements of Rule 144. Any selling shareholder who uses this prospectus to sell his or her shares will be subject to the prospectus delivery requirements of the Securities Act.

Regulation M under the Exchange Act provides that during the period that any person is engaged in the distribution of our shares of common stock, as defined in Regulation M, such person generally may not purchase our common stock. The selling shareholders are subject to these restrictions, which may limit the timing of purchases and sales of our common stock by the selling shareholders. This may affect the marketability of our common stock.

The selling shareholders may use agents to sell the shares. If this happens, the agents may receive discounts or commissions. The selling shareholders do not expect these discounts and commissions to exceed what is customary for the type of transaction involved. If required, a supplement to this prospectus will set forth the applicable commission or discount, if any, and the names of any underwriters, broker, dealers or agents involved in the sale of the shares. The selling shareholders and any underwriters, broker, dealers or agents that participate in the distribution of our common stock offered hereby may be deemed to be “underwriters” within the meaning of the Securities Act, and any profit on the sale of shares by them and any discounts, commissions, concessions or other compensation received by them may be deemed to be underwriting discounts and commissions under the Securities Act. The selling shareholders may agree to indemnify any broker or dealer or agent against certain liabilities relating to the selling of the shares, including liabilities arising under the Securities Act.

Upon notification by the selling shareholders that any material arrangement has been entered into with a broker or dealer for the sale of the shares through a block trade, special offering, exchange distribution or secondary distribution or a purchase by a broker or dealer, we will file a supplement to this prospectus, if required, pursuant to Rule 424(b) under the Securities Act, disclosing the material terms of the transaction.

We have agreed to indemnify in certain circumstances the selling shareholders against certain liabilities, including liabilities under the Securities Act. The selling shareholders have agreed to indemnify us in certain circumstances against certain liabilities, including liabilities under the Securities Act.

DESCRIPTION OF CAPITAL STOCK

Our authorized capital consists of 500,000,000 shares of capital stock. Such capital stock may be issued in classes or series of common or preferred stock pursuant to resolutions by our Board of Directors. Stock issued without the creation by the Board of a class or series is voting common stock. As of October 16, 2012, we had (i) 7,979,803 shares of voting common stock issued and outstanding and (ii) 522.5 shares of 15% Series A1 Convertible Preferred Stock issued and outstanding. The number of authorized shares of capital stock may be increased or decreased (but not below the number of shares then outstanding or otherwise reserved under obligations for issuance by us) by the affirmative vote of a majority of shares cast at a meeting of our shareholders at which a quorum is present.

The following discussion summarizes the rights and privileges of our capital stock. This summary is not complete, and you should refer to our articles of incorporation, as amended, which have been filed or incorporated as an exhibit to the registration statement of which this prospectus forms a part, as well as to the Colorado Business Corporation Act, for a more complete description covering the rights and liabilities of shareholders.

Voting Common Stock

We have authority to issue 499,000,000 shares of common stock. The holders of our common stock are entitled to one non-cumulative vote for each share held of record on all matters on which shareholders may vote at all meetings of our shareholders, including the election of directors, which currently is for the election of four out of seven directors. Cumulative voting for directors is not permitted. Except as provided by special agreement, the holders of common stock are not entitled to any preemptive, subscription, or conversion rights and the shares are not redeemable or convertible. All outstanding common stock is, and all voting common stock issuable upon conversion of the convertible preferred stock will be, when issued and paid for, fully paid and nonassessable.

Our articles of incorporation, as amended, and bylaws do not include any provision that would delay, defer or prevent a change in control of our company. However, pursuant to the laws of the State of Colorado, certain significant transactions would require the affirmative vote of a majority of the shares eligible to vote at a meeting of shareholders which requirement could result in delays to or greater cost associated with a change in control of the company.

The holders of our common stock have equal ratable rights to dividends, as and when declared by our Board of Directors from legally available funds. We have not paid any dividends nor do we anticipate paying any dividends on our voting common stock in the foreseeable future. It is our present policy to retain earnings, if any, for use in the development of our business. In addition, we may not pay cash dividends on our common stock for so long as any shares of our convertible preferred stock are outstanding.

Upon any voluntary or involuntary liquidation, dissolution or winding up of our affairs, the holders of our common stock are entitled to share ratably in all our assets remaining after payment to creditors and prior to distribution rights, if any, of any series of outstanding preferred stock.

Preferred Stock

We are authorized to issue up to 1,000,000 shares of preferred stock. Shares of preferred stock may be issued from time to time in one or more series as may be determined by our Board of Directors. The voting powers and preferences, the relative rights of each such series and the qualifications, limitations and restrictions of each series will be established by the Board of Directors. Our directors may authorize series of preferred stock with multiple votes per share and dividend rights which would have priority over any dividends paid with respect to the holders of our common stock. The issuance of preferred stock with these rights may make the removal of management difficult even if the removal would be considered beneficial to shareholders generally, and will have the effect of limiting shareholder participation in transactions such as mergers or tender offers if these transactions are not favored by our management. As of the date of this prospectus, the convertible preferred stock, which is described below, is the only series of preferred stock that is issued and outstanding.

Description of 15% Series A1 Convertible Preferred Stock

Authorized Shares, Stated Value and Liquidation Preference . Seven hundred fifty shares are designated as the convertible preferred stock with a stated value and liquidation preference of $10,000 per share. We issued 522.50 shares of the convertible preferred stock in a private placement that closed on November 29, 2011.

Ranking. The convertible preferred stock ranks senior to future classes or series of preferred stock established after the issue date of the convertible preferred stock, unless the Company’s Board of Directors expressly provides otherwise when establishing a future class or series. The convertible preferred stock ranks senior to the Company’s common stock.

Dividends . Holders of convertible preferred stock are entitled to receive dividends at an annual rate of 15.0% of the $10,000 per share liquidation preference, payable semi-annually. Dividends are payable in cash or in shares of common stock (at $1.65 per common share value), at the election of the Company.

Voting Rights . The holders of the convertible preferred stock will vote together with the holders of voting common stock as a single class on all matters upon which the holders of common stock are entitled to vote, except that the common stock will elect four directors and the convertible preferred stock will elect three directors. To date the holders of convertible common stock have not exercised their right to elect directors. Each share of convertible preferred stock will be entitled to such number of votes as the number of shares of common stock into which such share of convertible preferred stock is convertible; however, solely for the purpose of determining such number of votes, the conversion price per share will be deemed to be $3.30, subject to customary anti-dilution adjustment. In addition, the holders of the convertible preferred stock will vote as a separate class with respect to certain matters, including amendments to our articles of incorporation that alter the voting powers, preferences and special rights of the convertible preferred stock.

Liquidation. In the event the Company voluntarily or involuntarily liquidates, dissolves or winds up, the holders of the convertible preferred stock will be entitled, before any distribution or payment out of our assets may be made to or set aside for the holders of any of the junior capital stock and subject to the rights of creditors, to receive a liquidation distribution in an amount equal to $10,000 per share, plus any unpaid dividends. A merger, consolidation or sale of all or substantially all of our property or business is not deemed to be a liquidation for purposes of the preceding sentence.

Redemption. The convertible preferred stock is redeemable in whole or in part at the Company’s option at any time. The redemption price is equal to $10,000 per share, plus any unpaid dividends.

Preemptive Rights. Holders of the convertible preferred stock do not have preemptive rights.

Mandatory Conversion. Each share of convertible preferred stock remaining outstanding will automatically be converted into shares of our voting common stock upon the earlier of (i) any closing of an underwritten offering by the Company of shares of common stock to the public pursuant to an effective registration statement under the Securities Act, in which the aggregate cash proceeds to be received by the Company and selling shareholders (if any) from such offering (without deducting underwriting discounts, expenses and commissions) are at least $15,000,000, and the price per share paid by the public for such shares is at least $3.30 (such price to be adjusted for any stock dividends, combinations or splits or (ii) the date agreed to by written consent of the holders of a majority of the outstanding convertible preferred stock.

Optional Conversion by Investors . At any time, each holder of convertible preferred stock has the right, at such holder’s option, to convert all or any portion of such holder’s convertible preferred stock into shares of our common stock prior to the mandatory conversion of the convertible preferred stock at a price of $3.30 per share.

Optional Conversion by the Company. Beginning March 30, 2012, if the closing price of our common stock on the Trading Market is $4.50 or more for 20 consecutive trading days, then up to 25% of the outstanding stated value of the convertible preferred stock, plus any accrued and unpaid dividends, will be subject to conversion into our voting common stock at our option. For each period that the closing price of the common stock is at least $4.50 for another period of 20 consecutive trading after the first 20 day period, the Company will have the right to force conversion of another 25% of the outstanding convertible preferred stock.

Conversion Price. Each share of convertible preferred stock is convertible into shares of common stock at a conversion price of $3.30 per share, subject to customary anti-dilution adjustments, including in connection with stock dividends and distributions, stock splits, subdivisions and combinations.

Redemption by Holder. Unless prohibited by Colorado law governing the Company, upon 90 days’ prior written request from any holders of outstanding shares of convertible preferred stock, the Company may, at its discretion, redeem at a redemption price equal to the sum of (i) $10,000 per share and (ii) the accrued and unpaid dividends thereon, to the redemption date, up to one-third of each holder’s outstanding shares of convertible preferred stock on: (i) the first anniversary of the original issuance date, (ii) the second anniversary of the original issuance date; and (iii) the third anniversary of the original issuance date. The redemption price for any shares of convertible preferred stock shall be payable on the redemption date to the holder of such shares against surrender of the certificate(s) evidencing such shares to the Company. The Company may instead at its option, reduce the applicable conversion price by 50% with respect to the shares of convertible preferred stock for which redemption has been requested.

Registration Rights. We agreed to registration rights with the investors of the convertible preferred stock which provides that, within 180 days of the final closing of the private placement, we would use our commercially reasonable best efforts to file a resale registration statement, which we refer to as the resale registration statement, with the SEC covering the resale of the shares of our voting common stock issued or issuable upon conversion of the convertible preferred stock as well as any shares issued as payment for dividends, which we refer to as the registrable securities. Thereafter, we have agreed to use commercially reasonable best efforts to cause the resale registration statement to be declared effective within 30 days after the filing if granted no review or in the event the resale registration statement is subject to review by the SEC, 120 days after the filing. In either event, we will cause the resale registration statement to be declared effective as soon as practicable.

We will compensate the holders of registrable securities at a rate per month in common stock of 10% of the notational preferred stock outstanding should we fail to meet the deadlines for filing the resale registration statement and the effectiveness of the resale registration statement. For example, one month’s worth of common stock with $5.225 million of outstanding convertible preferred stock would be 158,333 shares of common stock ($5,225,000 divided by $3.30 times 10%). This prospectus is part of the resale registration statement that we were required to file with the SEC as described above.

SHARES ELIGIBLE FOR FUTURE SALE

Sales of substantial amounts of common stock in the public market after this offering could cause the market price of our common stock to decline. Those sales also might make it more difficult for us to sell equity-related securities in the future or reduce the price at which we could sell any equity-related securities.

Of the outstanding shares not offered by this prospectus, 3,679,478 shares are eligible for sale in the future that have not been registered for public sale.

Rule 144

Under Rule 144, a person who has beneficially owned restricted shares of our common stock for at least six months would be entitled to sell their shares provided that (i) such person is not deemed to have been one of our affiliates at the time of, or at any time during the three months preceding, a sale; and (ii) if the sale occurs prior to satisfaction of a one-year holding period, if we are current in our filings under the Exchange Act.

Persons who have beneficially owned restricted shares of our common stock for at least six months but who are our affiliates at the time of, or at any time during the three months preceding, a sale, would be subject to additional restrictions, by which such person would be entitled to sell within any three-month period only a number of shares that does not exceed the greater of:

•

1% of the total number of shares of the same class then outstanding, which will equal 79,798 shares as of October 16, 2012; or

•

the average weekly trading volume of such shares during the four calendar weeks preceding the filing of a notice on Form 144 with respect to such sale,

Any sales under Rule 144 by affiliates must also comply with the manner of sale, current public information and notice provisions of Rule 144.

DISCLOSURE OF COMMISSION POSITION

ON INDEMNIFICATION FOR SECURITIES ACT LIABILITIES

Our directors and officers are indemnified as provided by the Colorado Business Corporation Act, our articles of incorporation, as amended, and our bylaws as described in more detail under “Security Ownership of Certain Beneficial Owners and Management – Indemnification” beginning on page 40.

Insofar as indemnification for liabilities arising under the Securities Act of 1933 (the “Securities Act”) may be permitted to director, officers and controlling persons of our company pursuant to the foregoing provisions, or otherwise, we have been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 to register the shares of our common stock offered by this prospectus. This prospectus is part of that registration statement and, as permitted by the SEC’s rules, does not contain all of the information set forth in the registration statement. For further information about us or our common stock, you may refer to the registration statement and to the exhibits filed as part of the registration statement. The description of all agreements or the terms of those agreements contained in this prospectus are specifically qualified by reference to the agreements, filed or incorporated by reference in the registration statement.

We are subject to the informational requirements of the Exchange Act, as amended and, accordingly, file reports, proxy statements and other information with the SEC. You may read and copy the registration statement, these reports and other information at the SEC’s Public Reference Rooms at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the Public Reference Rooms. You can also obtain copies of our SEC filings by going to the SEC’s website at http://www.sec.gov or by visiting our website at www.arêteindustries.com and clicking on the Investor Relations tab at the top of our homepage and then selecting “SEC Filings” in the drop down menu.

LEGAL MATTERS

We have been advised on the legality of the shares of our common stock included in this prospectus by Jones & Keller, P.C., of Denver, Colorado.

EXPERTS

Our audited financial statements as of December 31, 2011 and for the year ended December 31, 2011, included in this prospectus have been included in reliance on the report of Causey Demgen & Moore P.C., our independent registered public accounting firm, for the period and to the extent set forth in its report. Our audited financial statements as of December 31, 2010 and for the year ended December 31, 2010, included in this prospectus have been included in reliance on the report of Ronald R. Chadwick, P.C. our former independent registered public accounting firm, for the period and to the extent set forth in his report. The audited financial information for the years ended December 31, 2009 and 2010 related to the oil and gas properties acquired on July 29, 2011, included in this prospectus have been included in reliance on the report of Causey Demgen & Moore P.C., our independent registered public accounting firm, for the period and to the extent set forth in its report. These financial statements have been included on the authority of such firms given their authority as experts in auditing and accounting.

Information about our estimated net proved reserves and the future net cash flows attributable to the oil and natural gas reserves of Arête Industries, Inc. as of December 31, 2011 contained in this prospectus was prepared by Ryder Scott Company, L.P., an independent reserve engineer and geological firm, and is included or incorporated here in reliance upon their authority as experts in oil and gas reserves and present values thereof.

CERTAIN DEFINITIONS

Unless the context in this prospectus otherwise requires, the terms the “Company”, “we”, “us”, “our” or “ours” when used in this prospectus refer to Arête Industries, Inc., together with its consolidated subsidiaries. When the context requires, we refer to these entities separately.

We have included below the definitions for certain terms used in this prospectus:

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

Bbls/d or BOPD — barrels per day or barrels of oil per day.

BOE — Barrel of oil equivalent, determined using a ratio of six Mcf of natural gas equal to one barrel of oil equivalent.

Carried interest — A contractual arrangement, usually in a drilling project, whereby all or a portion of the working interest cost participation of the project originator is paid for by another party in exchange for earning an interest in such project.

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

Compression — A force that tends to shorten or squeeze, decreasing volume or increasing pressure.

DD&A — Depreciation, depletion and amortization.

Developed acreage — The number of acres which are allotted or assignable to producing wells or wells capable of production.

Development activities — Activities following acquisition or exploration including the drilling and completion of additional wells and the installation of production facilities.

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

Dry hole or well — A well found to be incapable of producing hydrocarbons economically.

Exploitation — The act of making an oil and gas property more profitable, productive or useful.

Exploratory well — A well drilled to find and produce oil or natural gas reserves in an area or to a potential reservoir not classified as proved.

Farm-in or Farm-out — An agreement whereby the owner of a working interest in an oil and natural gas lease assigns or contractually conveys subject to future assignment the working interest or a portion thereof to another party who desires to drill on the leased acreage. Generally, the farmee is required to drill one or more wells in order to earn its interest in the acreage. The farmor usually retains a royalty and/or after payout interest in the lease. The interest received by the farmee is a “farm-in” while the interest transferred by the farmor is a “farm-out.”

FASB — The Financial Accounting Standards Board.

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

GAAP — Generally accepted accounting principles in the United States of America.

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

MBbls — One thousand barrels of crude oil or other liquid hydrocarbons.

MBOE — one thousand barrels of oil equivalent, determined using a ratio of six Mcf of natural gas equal to one barrel of oil equivalent.

Mbtu (Mmbtu) — Used as a standard unit of measurement for natural gas and provides a convenient basis for comparing the energy content of various grades of natural gas and other fuels. One cubic foot of natural gas produces approximately 1,000 BTUs, so 1,000 cubic feet of gas is comparable to 1 Mbtu. Mbtu is often expressed as MMbtu, which is intended to represent a thousand BTUs.

Mcf — One thousand cubic feet.

Mmcf — One million cubic feet.

Net acres or net wells — The sum of the fractional working interests owned in gross acres or gross wells.

NGL’s — Natural gas liquids measured in barrels.

NRI or Net Revenue Interests — The share of production after satisfaction of all royalty, oil payments and other non-operating interests.

Plugging and abandonment or P&A — Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another stratum or to the surface.

PV10 — The present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with SEC guidelines, net of estimated lease operating expense, production taxes and future development costs, using prices and costs, as prescribed in the SEC rules, as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service, depreciation, depletion, amortization and accretion, or Federal income taxes and discounted using an annual discount rate of 10%. PV10 is considered a Non-GAAP financial measure as defined by the SEC.

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

Proved developed nonproducing reserves or PDNP — Proved reserves that meet the definition of proved developed reserves (defined below) but are either shut-in or are behind-pipe reserves.

Proved developed producing reserves or PDP — Proved reserves that meet the definition of proved developed reserves (defined below) that are currently able to produce to market.

Proved developed reserves — Proved developed oil and gas reserves are reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the costs of the required equipment is relatively minor compared to the costs of a new well.

Proved reserves — Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimates. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

Proved undeveloped reserves or PUDs — Proved undeveloped oil and gas reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time

Reasonable certainty — If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least 90 percent probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical or geochemical) engineering, and economic data are made to estimated ultimate recovery with time, reasonably certain estimated ultimate recovery is much more likely to increase or remain constant than to decrease.

Re-engineering — a process involving a comprehensive review of the mechanical conditions associated with wells and equipment in producing fields. Our re-engineering practices typically result in a capital expenditure plan, which is implemented over time, to workover (see below) and re-complete wells and modify down-hole artificial lift equipment and surface equipment and facilities. The programs are designed specifically for individual fields to increase and maintain production, reduce down-time and mechanical failures, lower per-unit operating expenses, and therefore, improve field economics.

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

Royalty interest — An interest in an oil and natural gas property entitling the owner to a share of oil or natural gas production free of costs of production.

SEC — The U.S. Securities and Exchange Commission.

Secondary recovery — The use of water-flooding or gas injection to maintain formation pressure during primary production and to reduce the rate of decline of the original reservoir drive.

Shut-in reserves — Those reserves expected to be recovered from completion intervals that were open at the time the reserves were estimated but were not producing due to market conditions, mechanical difficulties or because production equipment or pipelines were not yet installed. These reserves are included in the PDNP category on the reserve report.

Standardized Measure of Discounted Future Net Cash Flows — A measure of the present value of the estimated future cash flows to be derived from the production and sale of proved oil and gas reserves. Estimated production taxes, estimated operating expenses, estimated future investment costs, and estimated future income taxes are deducted from estimated future cash inflows and discounted at PV 10 to arrive at the standardized measure of discounted future net cash flows. We calculate this measure in accordance with FASB ASC Topic (932) Extractive Activities – Oil and Gas .

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

Working interest or WI — The ownership interest, generally defined in a joint operating agreement, that gives the owner the right to drill, produce and/or conduct operating activities on the property and share in the sale of production, subject to all royalties, overriding royalties and other burdens and obligates the owner of the interest to share in all costs of exploration, development, and production and all risks in connection therewith.

Workover — Major remedial operations on a completed well to restore, maintain or improve the well’s production.

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES


INDEX TO AUDITED ANNUAL FINANCIAL STATEMENTS

Reports of Independent Registered Public Accounting Firm			F-2

Consolidated Balance Sheets – December 31, 2010 and 2011			F-4

Consolidated Statements of Operations – For the years ended December 31, 2010 and 2011			F-5

Consolidated Statements of Stockholders’ (Equity) Deficit – For the years ended December 31, 2010 and 2011			F-6

Consolidated Statements of Cash Flows – For the years ended December 31, 2010 and 2011			F-7

Notes to Consolidated Financial Statements for the years ended December 31, 2010 and 2011			F-8

INDEX TO UNAUDITED INTERIM FINANCIAL STATEMENTS

Unaudited Consolidated Balance Sheets – December 31, 2011 and June 30, 2012			F-21

Unaudited Consolidated Statements of Operations – For the six-months ended June 30, 2011 and 2012			F-23

Unaudited Consolidated Statements of Stockholders’ (Equity) Deficit – For the six-months ended June 30, 2012			F-24

Unaudited Consolidated Statements of Cash Flows – For the six-months ended June 30, 2011 and 2012			F-25

Notes to Unaudited Consolidated Financial Statements for the six-months ended June 30, 2011 and 2012			F-26

INDEX TO FINANCIAL INFORMATION OF ACQUIRED PROPERTIES

Report of Independent Registered Public Accounting Firm			F-33

Statements of Operating Revenues and Direct Operating Expenses of Oil & Gas Working Interests Acquired by Arête Industries, Inc. (excluding the “Separate Interests” Described in Note 1)			F-34

Notes to Statements of Operating Revenues and Direct Operating Expenses			F-35

Unaudited Pro Forma Consolidated Balance Sheet – June 30, 2011			F-42

Unaudited Pro Forma Consolidated Statement of Operations – For the year ended December 31, 2010			F-43

Unaudited Pro Forma Consolidated Statement of Operations – For the six months ended June 30, 2011			F-44

Notes to Unaudited Pro Forma Consolidated Financial Statements			F-45

F-1

CAUSEY DEMGEN & MOORE P.C.

1125 Seventeenth Street, Suite 1450

Denver, Colorado 80202

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders

of Arête Industries, Inc.

We have audited the accompanying consolidated balance sheet of Arête Industries, Inc. and Subsidiaries as of December 31, 2011, and the related consolidated statements of operations, stockholders’ equity (deficit) and cash flows for the year then ended. 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 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 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 audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Arête Industries, Inc. and Subsidiaries at December 31, 2011, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.

Denver, Colorado

April 16, 2012

/s/ CAUSEY DEMGEN & MOORE P.C.

F-2

RONALD R. CHADWICK, P.C.

Certified Public Accountant

2851 South Parker Road, Suite 720

Aurora, Colorado 80014

Telephone (303)306-1967

Fax (303)306-1944

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors

Arête Industries, Inc.

Westminster, Colorado

I have audited the accompanying consolidated balance sheet of Arête Industries, Inc. and Subsidiaries as of December 31, 2010, and the related consolidated statements of operations, stockholders’ deficit, and cash flows for the year then ended. These financial statements are the responsibility of the Company’s management. My responsibility is to express an opinion on these financial statements based on my audit.

I conducted my audit in accordance with the audit standards of the Public Company Accounting Oversight Board (United States). Those standards require that I 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. I believe that my audit provides a reasonable basis for my opinion.

In my opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Arête Industries, Inc. and Subsidiaries at December 31, 2010, and the consolidated results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the financial statements, the Company has suffered recurring losses from operations, has a working capital deficit and a stockholders’ deficit, and is delinquent on the payment of creditor liabilities including payroll taxes. These conditions raise substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 1. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.


March 28, 2011						/s/ Ronald R. Chadwick, P.C.
Aurora, Colorado						RONALD R. CHADWICK, P.C.

F-3

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

December 31, 2010 and 2011


	2010			2011
ASSETS
Current Assets:
Cash and equivalents	$	15,990		$	219,566
Receivable from DNR Oil & Gas, Inc.:
Oil and gas sales, net of production costs		—			165,283
Other		12,625			15,597
Prepaid expenses and other		85,139			207,338

Total Current Assets		113,754			607,784

Property and Equipment:
Oil and gas properties, at cost, successful efforts method:
Proved properties		—			9,056,032
Unproved properties		—			287,728
Natural gas gathering system		442,195			442,195
Furniture and equipment		19,662			22,522

Total property and equipment		461,857			9,808,477
Less accumulated depreciation, depletion and amortization		(184,121	)		(525,154	)

Net Property and Equipment		277,736			9,283,323

TOTAL ASSETS	$	391,490		$	9,891,107

LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
Current Liabilities:
Accounts payable:
Payable to DNR Oil & Gas, Inc.:
Oil and gas property acquisition costs	$	—		$	826,791
Gas gathering operating costs		402,558			416,835
Operator fees and other		117,518			151,748
Unrelated parties		60,029			92,019
Notes and advances payable:
Directors		704,475			109,319
Unrelated parties		—			250,000
Accrued interest expense		152,943			88,303
Director fees payable		98,000			90,000
Commissions payable for private placement of preferred stock		—			105,000
Accrued payroll taxes		111,690			—
Accrued consulting services payable in common stock		536,528			18,750
Current portion of asset retirement obligations		—			15,398
Other accrued costs and expenses		40,596			111,061

Total Current Liabilities		2,224,337			2,275,224
Asset Retirement Obligations , net of current portion		—			637,842

Total Liabilities		2,224,337			2,913,066

Commitments and Contingencies (Notes 3, 4 and 10)
Stockholders’ Equity (Deficit):
Convertible Class A preferred stock; $10,000 face value per share, authorized 1,000,000 shares:
Series 1; authorized 30,000 shares, issued and outstanding no shares in 2010 and 522.5 shares in 2011, liquidation preference of $5,421,000 in 2011		—			5,023,371
Series 2; authorized 2,500 shares, issued and outstanding no shares in 2010 and 2011		—			—
Common stock, no par value; authorized 499,000,000 shares, issued and outstanding 4,972,635 in 2010 and 7,764,476 in 2011		13,611,903			16,904,154
Accumulated deficit		(15,444,750	)		(14,949,484	)

Total Stockholders’ Equity (Deficit)		(1,832,847	)		6,978,041

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)	$	391,490		$	9,891,107

The Accompanying Notes are an Integral Part of These Financial Statements.

F-4

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

Years Ended December 31, 2010 and 2011


	2010			2011
Revenues:
Oil and natural gas sales	$	—		$	1,005,149
Gas gathering income		167,625			45,638

Total revenues		167,625			1,050,787

Operating Expenses:
Oil and gas producing activities:
Lease operating expenses		—			449,854
Production taxes		—			89,109
Depreciation, depletion, amortization and accretion		—			310,308
Gas gathering:
Cost of operations:
Related Party		104,606			30,815
Unrelated parties		222,985			92,420
Depreciation		44,229			44,219
General and administrative expenses:
Director fees		100,450			120,000
Investor relations		138,889			309,703
Acquisition investigation and due diligence		22,050			514,579
Legal, auditing and transfer agent		30,974			198,873
Accounting, financial reporting and rent- related party		53,000			83,802
Consulting fees:
Related parties		122,500			167,500
Unrelated parties		238,700			297,950
Office, travel and other		16,546			46,441
Depreciation		—			570

Total operating expenses		1,094,929			2,756,143

Operating loss		(927,304	)		(1,705,356	)

Other income (expense):
Gain on sale of oil and natural gas properties		—			2,479,934
Gain on extinguishment of debt		121,870			111,690
Interest income		13			604
Interest expense		(47,191	)		(391,606	)

Income (loss) before income taxes		(852,612	)		495,266
Income tax benefit (expense)		—			—

Net income (loss)	$	(852,612	)	$	495,266

Net Income (Loss) Applicable to Common Stockholders:
Net income (loss)	$	(852,612	)	$	495,266
Accrued Preferred stock dividends		—			(196,000	)

Net income (loss) applicable to common stockholders	$	(852,612	)	$	299,266

Earnings (Loss) Per Share Applicable to Common Stockholders:
Basic	$	(0.17	)	$	0.04

Diluted	$	(0.17	)	$	0.04

Weighted Average Number of Common Shares Outstanding:
Basic		4,950,000			6,875,000

Diluted		4,950,000			6,875,000

The Accompanying Notes are an Integral Part of These Financial Statements.

F-5

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (DEFICIT)

For the Years Ended December 31, 2010 and 2011


	Class A Preferred Stock					Common Stock				Accumulated Deficit			Total
	Shares		Amount			Shares		Amount		Accumulated Deficit			Total
Balances, December 31, 2009		—	$	—			4,932,635	$	13,587,403	$	(14,592,138	)	$	(1,004,735	)
Issuance of common stock for services		—		—			40,000		24,500		—			24,500
Net loss		—		—			—		—		(852,612	)		(852,612	)


Balances, December 31, 2010		—		—			4,972,635		13,611,903		(15,444,750	)		(1,832,847	)
Issuance of common stock for services:
Settlement of liabilities to unrelated parties at $0.68 per share		—		—			770,000		481,251		—			481,251
Settlement of liabilities to related parties at $0.88 per share							770,000		675,000					675,000
Consulting related to property acquisition at $6.10 per share		—		—			75,000		457,500		—			457,500
Services related to financing transaction at $4.00 per share		—		—			3,000		12,000		—			12,000
Board of Director fees at $1.75 per share		—		—			72,841		128,000					128,000
Issuance of common stock in exchange for notes payable to:
Officers and directors at $8.00 per share		—		—			62,500		500,000		—			500,000
Others at $1.00 per share		—		—			835,000		835,000		—			835,000
Issuance of common stock for cash of $1.00 per share		—		—			203,500		203,500		—			203,500
Issuance of Class A (Series 1) preferred stock for cash:
Director for $10,000 per share		100.0		1,000,000			—		—		—			1,000,000
Others at $10,000 per share		422.5		4,225,000			—		—		—			4,225,000
Offering costs related to issuance of preferred stock		—		(201,629	)		—		—		—			(201,629	)
Net income		—		—			—		—		495,266			495,266

Balances, December 31, 2011		522.5	$	5,023,371			7,764,476	$	16,904,154	$	(14,949,484	)	$	6,978,041

The Accompanying Notes are an Integral Part of These Financial Statements.

F-6

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2010 and 2011


	2010			2011
Cash Flows from Operating Activities:
Net income (loss)	$	(852,612	)	$	495,266
Adjustments to reconcile net income (loss) to net cash used in operating activities:
Depreciation, depletion and amortization		44,229			341,033
Accretion of discount on asset retirement obligations					14,064
Common stock issued in exchange for services		573,889			1,235,973
Gain on extinguishment of debt		(121,869	)		(111,690	)
Gain on sale of oil and gas properties		—			(2,479,934	)
Changes in operating assets and liabilities:
Accounts receivable		9,068			(183,979	)
Prepaid expenses and other		—			(122,199	)
Accounts payable		110,552			59,397
Accrued costs and expenses		23,619			(2,175	)

Net cash used in operating activities		(213,124	)		(754,244	)

Cash Flows from Investing Activities:
Capital expenditures for oil and gas properties		—			(1,128,810	)
Purchase of furniture and equipment		—			(2,860	)

Net cash used in investing activities		—			(1,131,670	)

Cash Flows from Financing Activities:
Proceeds from notes and advance payable		215,000			2,064,100
Principal payments on notes payable		(2,650	)		(5,306,481	)
Proceeds from sale of common stock		—			203,500
Proceeds from sale of preferred stock		—			5,225,000
Offering costs related to private placement of preferred stock		—			(96,629	)

Net cash provided by financing activities		212,350			2,089,490

Net increase (decrease) in cash and equivalents		(774	)		203,576
Cash and equivalents, beginning of year		16,764			15,990

Cash and equivalents, end of year	$	15,990		$	219,566

Supplemental Disclosure of Cash Flow Information:
Cash paid for interest	$	10,848		$	319,246

Cash paid for income taxes	$	—		$	—

Supplemental Disclosure of Non-cash Investing and Financing Activities:
Conversion of notes payable to 897,500 shares of common stock	$	—		$	1,335,000

Note payable for acquisition of oil and gas properties	$	—		$	10,100,000

Proceeds from sale of oil and gas property applied to note payable	$	—		$	5,101,047

Pre-acquisition oil and gas sales applied to note payable	$	—		$	766,728

Non-interest bearing payable for acquisition of oil and gas properties	$	—		$	576,791

Asset retirement obligations incurred on acquisition of oil and gas properties	$	—		$	639,176

The Accompanying Notes are an Integral Part of These Financial Statements.

F-7

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010 and 2011

1. Organization and Nature of Operations

Arête Industries, Inc. (“Arête” or the “Company”), is a Colorado corporation that was incorporated on July 21, 1987. The Arête subsidiary, Aggression Sports, Inc. (Aggression Sports) is inactive with no assets, liabilities or operations. Arête has operated a natural gas gathering system in Wyoming since 2006 and on July 29, 2011 the Company purchased oil & natural gas properties in Colorado, Montana, Kansas, and Wyoming.

The consolidated financial statements of the Company include the accounts of Arête for the entire period and Aggression Sports since October 1, 2001. All intercompany accounts have been eliminated in the consolidation.

The Company is focused entirely on acquiring interests in traditional oil and gas ventures. In the oil and gas field, the Company is looking for conservative projects that offer high profit, low risk projects including overlooked and by-passed reserves of natural gas, which will include shut-in and in-field development, stripper wells, re-completion and re-working projects. The Company will seek to make investments for direct participations in the revenue streams from such projects on a project finance basis, as well as through acquisition of management, capital, and assets by one or more acquisitions of going concerns.

2. Summary of significant accounting policies

Basis of presentation

The Company follows accounting principles generally accepted in the United States of America. (“GAAP”).

Use of estimates

Preparation of the Company’s financial statements in accordance with GAAP requires management to make various assumptions, judgments and estimates that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts initially established.

The only component of comprehensive income that is applicable to the Company is net income (loss). Accordingly, a separate statement of comprehensive income (loss) is not included in these financial statements.

Reclassifications

A reclassification was made on the December 31, 2010 balance sheet and December 31, 2010 cash flow statement. It was determined that a prepaid expense and a payable should not have been recorded for consulting services which were to be paid in stock but the stock had not been issued . This reclassification did not have any impact on the Company’s previously reported working capital, results of operations or net cash flows. In the Company’s 2011Consolidated Statement of Operations included in its annual report on Form 10-K, the gain on sale of oil and gas properties described in Note 3 of $2,479,934 was included in operating revenue. This amount was reclassified as non-operating income in the accompanying Consolidated Statement of Operations for the year ended December 31, 2011.

Principles of Consolidation

The consolidated financial statements of the Company include the accounts of Arête and its inactive subsidiary, Aggression Sports. All intercompany accounts and transactions have been eliminated in consolidation.

Cash and cash equivalents

For purposes of the statement of cash flows, the Company considers cash and all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.

F-8

Gas gathering system, furniture and equipment

The gas gathering system, furniture and equipment are stated at cost. Material expenditures that increase the life of an asset are capitalized and depreciated over the estimated remaining useful life of the asset. The cost of normal maintenance and repairs is charged to operating expenses as incurred. Upon disposal of an asset, the cost of the asset and the related accumulated depreciation are removed from the accounts, and any gains or losses will be reflected in current operations. For the gas gathering system, depreciation is computed using the straight line method over an estimated useful life of ten years. Depreciation of furniture and equipment is computed using the straight-line method over an estimated useful life of five years.

Oil and Gas Producing Activities

The Company’s oil and gas exploration and production activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense and included within cash flows from investing activities in the Consolidated Statements of Cash Flows. The costs of development wells are capitalized whether productive or nonproductive. Oil and gas lease acquisition costs are also capitalized.

The Company reviews its proved oil and gas properties for impairment annually or whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected undiscounted future cash flows of its oil and gas properties and compares such undiscounted future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, recent sales prices of comparable properties, the present value of estimated future cash flows, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected.

The provision for DD&A of oil and gas properties is calculated based on proved reserves on a field-by-field basis using the unit-of-production method. Natural gas is converted to barrel equivalents, BOE, at the rate of six Mcf of natural gas to one barrel of oil. Estimated future dismantlement, restoration and abandonment costs, which are net of estimated salvage values, are taken into consideration.

In January 2010, the Financial Accounting Standards Board (“FASB”) issued authoritative oil and gas reserve estimation and disclosure guidance that was effective for the Company beginning in 2010. This guidance was issued to align the accounting oil and gas reserve estimation and disclosure requirements with the requirements in the SEC final rule, “Modernization of Oil and Gas Reporting ”, which was also effective in 2010. Many of the revisions are updates to definitions in the existing oil and gas rules to make them consistent with the Petroleum Resource Management System, which was developed by several petroleum industry organizations and is a widely accepted standard for the management of petroleum resources. Key revisions include a requirement to use 12-month average pricing determined by averaging the first of the month prices for the preceding 12 months rather than year-end pricing for estimating proved reserves, the ability to include nontraditional resources in reserves, the ability to use new technology for determining proved reserves, and permitting disclosure of probable and possible reserves.

F-9

Asset Retirement Obligations

Revenue Recognition

The Company records revenues from the sales of natural gas, natural gas liquids (“NGL”) and crude oil when delivery to the purchaser has occurred and title has transferred. The Company uses the sales method to account for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold by the Company. In addition, the Company will record revenue for its share of gas sold by other owners that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company also reduces revenue for other owners’ gas sold by the Company that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company’s remaining over- and under-produced gas balancing positions are considered in the Company’s proved oil and gas reserves. Gas imbalances at December 31, 2010 and 2011 were not material.

Environmental Liabilities

Environmental expenditures that relate to an existing condition caused by past operations and that do not contribute to current or future revenue generation are expensed. Liabilities are accrued when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. As of December 31, 2010 and 2011, the Company had not accrued for nor been fined or cited for any environmental violations that would have a material, adverse effect upon capital expenditures, operating results or the competitive position of the Company.

Industry Segment and Geographic Information

The Company operates in one industry segment, which is the exploration, development and production of natural gas and crude oil, and all of the Company’s operations are conducted in the continental United States. Consequently, the Company currently reports as a single industry segment.

Stock based compensation

The Company has not granted any stock options or warrants during the years ended December 31, 2010 and 2011 and no options or warrants were outstanding at any time during these years. The Company has issued shares of common stock for services performed by officers, directors and unrelated parties during 2010 and 2011. The Company has recorded these transactions based on the value of the services or the value of the common stock, whichever is more readily determinable.

Income taxes

The Company accounts for income taxes under ASC 740. Temporary differences are differences between the tax basis of assets and liabilities and their reported amounts in the financial statements that will result in taxable or deductible amounts in future years. The Company’s temporary differences consist primarily of tax operating loss carry forwards and start-up costs capitalized for tax purposes.

Fair value of financial instruments

Cash, accounts payable, accrued liabilities and notes payable are carried in the financial statements in amounts which approximate fair value because of the short-term maturity of these instruments.

F-10

Earnings per share

New Accounting Pronouncements

In May 2011, the FASB issued new fair value measurement authoritative accounting guidance clarifying the application of fair value measurement and disclosure requirements and changes particular principles or requirements for measuring fair value. This authoritative accounting guidance is effective for interim and annual periods beginning after December 15, 2011. The Company is currently evaluating the provisions of this authoritative accounting guidance and assessing the impact, if any, it may have on the Company’s fair value disclosures beginning in the first quarter of 2012.

In June 2011, the FASB issued new authoritative accounting guidance that states an entity that reports items of other comprehensive income has the option to present the components of net income and comprehensive income in either one continuous financial statement, or two consecutive financial statements, including reclassification adjustments. In December 2011, the FASB issued new authoritative accounting guidance which effectively deferred the requirement to present the reclassification adjustments on the face of the financial statements. This authoritative accounting guidance is effective for interim and annual periods beginning after December 15, 2011. Based on the Company’s current operations and structure, the adoption of this standard is not expected to have an impact on the Company’s 2012 financial statements.

In January 2010, the FASB issued Accounting Standards Update 2010-06, Improving Disclosures about Fair Value Measurements , which amended FASB ASC 820, Fair Value Measurements and Disclosures. The intent of this update is to improve disclosure requirements related to fair value measurements and disclosures. New disclosures were required regarding transfers in and out of Levels 1 and 2 and activity within Level 3 fair value measurements, as well as clarification of existing disclosures regarding the level of disaggregation of derivative contracts and disclosures about fair value measurement inputs and valuation techniques. The guidance was effective for interim and annual periods beginning after December 15, 2009, except for the Level 3 reconciliation disclosures, which were effective for interim and annual periods beginning after December 15, 2010. The Company adopted the provisions on January 1, 2010, except for the Level 3 reconciliation disclosures, which were adopted on January 1, 2011. Adoption of the disclosure requirements did not have a material impact on the Company’s financial position or results of operations.

In December 2010, the FASB issued Accounting Standards Update 2010-29, Business Combinations: Disclosure of Supplementary Pro Forma Information for Business Combinations , which amended FASB ASC Topic 805, Business Combinations . The objective of this update is to clarify and expand the pro forma revenue and earnings disclosure requirements for business combinations. The guidance was effective for fiscal years beginning after December 15, 2010, and the Company adopted the provision on January 1, 2011. Adoption of the disclosure requirements did not have a material impact on the Company’s financial position or results of operations.

In May 2011, the FASB issued Accounting Standards Update 2011-04, Fair Value Measurement: Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS , which amended FASB ASC Topic 820, Fair Value Measurement . The objective of this update is to create common fair value measurement and disclosure requirements between GAAP and International Financial Reporting Standards (“IFRS”). The amendments clarify existing fair value measurement and disclosure requirements and make changes to particular principles or requirements for measuring or disclosing information about fair value measurements. These amendments are not expected to have a significant impact on companies applying GAAP. This provision is effective for interim and annual periods beginning after December 15, 2011. Adoption of this update is not expected to have a material impact on the Company’s disclosures and financial statements.

3. Acquisitions and Disposition of Oil and Gas Properties

Acquisitions

F-11

purchase price for the properties was $10 million, of which the Company paid a nonrefundable down payment of $500,000 and the remaining $9.5 million was financed by the Sellers pursuant to a promissory note due July 1, 2011. The Company was unable to arrange the funding to pay the $9.5 million promissory note due on July 1, 2011, and therefore, the note was not paid. On July 29, 2011, the Company and Sellers entered into an Amended and Restated Purchase and Sale Agreement regarding the acquisition by the Company of the oil and gas properties. The material terms of the agreement are a base purchase price for the properties of $11 million to be paid by an initial payment of Nine Hundred Thousand and 00/l00 Dollars ($900,000.00), comprised of (i) a credit in the amount of Five Hundred Thousand and 00/l00 Dollars ($500,000.00) previously paid by Buyer in connection with the Original Purchase and Sale Agreement; and (ii) Four Hundred Thousand and 00/l00 Dollars ($400,000.00) in funds contemporaneously with the execution of the Agreement. The remaining principal balance of the base purchase price in the amount of Ten Million One Hundred Thousand and 00/l00 Dollars ($10,100,000.00), together with interest at the monthly interest rate of Eighty Three Hundredths of One Percent (0.83%), will be paid to Sellers in three monthly payments, with $3,700,000.00 due August 15, 2011 (extended to August 31, 2011), and $3,200,000.00 due on each of September 15, 2011 and October 15, 2011, closed September 29, 2011, and were paid in full on September 30, 2011.

The Company as part of the agreement received the production of oil and gas from April 1, 2011 and was responsible was the lease operating expenses for that period. The net proceeds of the production, production taxes, and lease operating expenses from April 1, 2011 to July 29, 2011 of $766,728 was applied to the carrying costs of the oil & natural gas properties.

The acquisition was structured whereby the Company acquired 100% of Seller’s interest in certain geologic zones of the properties. Presented below is a summary of agreed-upon values associated with the properties along with a discussion of the interests retained by the Sellers:


Rex Lake/ Big Hollow (WY)	$	511,025	*(b)*
Kansas		2,152,216	*(a)*
Montana		98,179	*(b)*
Wyoming		2,733,773	*(b)*
Buff (WY)		611,211	*(b)*
Colorado		2,507,678	*(a)*
School Creek (WY)		2,385,918	*(b)*

	$	11,000,000	*(c)*

(a)

(b)

The properties located in Wyoming and Montana provide a similar formula as used for Colorado and Kansas that could result in an obligation for additional purchase consideration to the extent that the Company performs future drilling or recompletion activities in formations that are not producing as of the closing date. Furthermore, if the Company sells properties where reserves have been proved up through drilling or recompletion, the Sellers have retained an interest of 70% in the net sales proceeds (after Arête receives a recovery of 125% of the original purchase allocation as contained in the table above). The maximum increase in purchase price for all properties shown in the table above is limited to a maximum of $25 million. Due to the sale of School Creek discussed below, the maximum future consideration has been reduced by approximately $4.6 million to $21.4 million.

(c)

Note that the values shown in this table are the allocation amounts attributable to the proved developed zones agreed to between the Company and the Sellers, before purchase adjustments for pre-acquisition net revenues received, oil in tanks and contingent purchase price adjustments. These adjustments do not modify the agreed upon value for purposes of the adjustments discussed above but will affect the purchase allocation under GAAP.

If the Company increases its proven producing net oil reserves or net gas reserves by drilling or recompletion on certain of the acquired properties in Colorado and Kansas, then the Company will pay $250,000 for every 20,000 bbl or 150,000 mcf increase respectively, which amount will be increased by a factor if the Nymex prices for oil or gas stay above a specified price floor for more than 60 days. Cumulative payments under the additional purchase price factor for the Colorado and Kansas properties are limited to $5 million. The Company will also make similar payments to Sellers if the Company increases reserves in the Wyoming properties, and the Company will make additional payments under a formula by which Sellers and the Company will share proceeds of sales or production from untapped formations on the properties to be acquired in Wyoming. Cumulative payments under the additional purchase price factor for the Wyoming properties are limited to $20 million. The aggregate of all additional purchase price payments from all factors is capped at $25 million.

F-12

The Company is in the process of evaluating the purchase and the allocation of the purchase price to all assets and liabilities acquired.

Dispositions

The Company also had an agreement for the right to receive a portion of the proceeds from sale of certain of the properties that could be sold before payment in full of the base purchase price and assignment of the properties to the Company. The School Creek properties were sold on August 23, 2011 and the Company received $5,101,047 for its share of the proceeds on the sale, which resulted in a gain on sale of $2,479,934. The Company applied the proceeds to the payments due under the purchase and sale agreement. On September 29, 2011 the Company paid the balance of $5,120,194 that included $121,241 of interest. The Company as part of the agreement received the production of oil and gas from April 1, 2011 and was responsible was the lease operating expenses for that period. The net proceeds of the production, production taxes, and lease operating expenses from April 1, 2011 to July 29, 2011 of $766,812 was applied to the carrying costs of the oil & natural gas properties.

The Company determined that this sale did not qualify for discontinued operations reporting and the gain is included in non-operating income in the 2011 Consolidated Statement of Operations.

4. Stock transactions

Common stock

Stock issuances:

During the year ended December 31, 2010, 40,000 shares of the Company’s common stock were issued to officers and directors for services. Of the total common shares issued in fiscal year ended December 31, 2010, 35,000 shares of common stock were issued to consultants and for fees.

The Company has authorized shares of 499,000,000 shares of Common Stock and has issued 4,972,635 shares of Common Stock as of December 31, 2010. The total of Common Stock obligated is 1,535,973 shares at December 31, 2010.

On April 11, 2011 the Company held its annual meeting. The shareholders voted to reverse split the common stock of the Company 100 for 1. The effective date of the reverse split was April 18, 2011. All references to shares have been restated to reflect the reverse stock split if it had occurred at the beginning of the earliest period presented.

During the year ended December 31, 2011, the Company had the following common stock issuances:

The Company issued 770,000 shares of common stock to third parties to pay its contract obligations and 770,000 shares to repay certain advances of directors’ common stock;

The board of directors authorized three of the directors to exchange $500,000 of their loans and advances to the Company for 62,500 shares of common stock or $8.00 per common share;

The Company issued 72,841 shares of common stock for its obligation for directors’ fees accrued of $128,000;

The Company sold 203,500 shares of common stock for cash of $203,500 to third parties;

The Company issued 75,000 shares for consulting services to a third party related to the acquisition of properties, such services valued at $457,500;

The Company issued 3,000 shares of common stock to three persons in exchange for loan fees payable to a stockholder, a third party and our CEO, of $12,000; and

The Company exchanged $835,000 of notes payable to 14 third parties for 835,000 shares of common stock.

Preferred stock

The Company recently undertook a private placement of its Preferred Stock Series A1 for the sale of 750 shares at $10,000 per share, on a “best efforts” basis with a minimum offering of 520 shares and maximum offering of 750 shares at $10,000 per share. On September 29, 2011 the Company closed on the minimum by issuing 522.5 shares or $5,225,000 received. The following are the terms of the Preferred Stock Series A1:

Authorized Shares, Stated Value and Liquidation Preference . Seven hundred fifty shares are designated as the Series A1 15% Convertible Preferred Stock, which has a stated value and liquidation preference of $10,000 per share.

F-13

Ranking . The Series A1 Preferred Stock will rank senior to future classes or series of preferred stock established after the issue date of the Series A1 Preferred Stock, unless the Company’s Board of Directors expressly provides otherwise when establishing a future class or series. The Series A1 Preferred Stock ranks senior to our common stock in liquidation and dissolution.

Dividends . Holders of Series A1 Preferred Stock are entitled to receive, when, as and if declared by our Board of Directors, non-cumulative dividends at an annual rate of 15.0% of the $10,000 per share liquidation preference. Declared dividends are payable in cash or in shares of Common Stock (at its then fair market value), at the election of the Company.

Voting Rights . The holders of the Series A1 Preferred Stock will vote together with the holders of common stock as a single class on all matters upon which the holders of common stock are entitled to vote, except that the common stock will elect four directors and the Series A1 Preferred Stock will elect three directors. Each share of Series A Preferred Stock will be entitled to such number of votes as the number of shares of common stock into which such share of Preferred Stock is convertible; however, solely for the purpose of determining such number of votes, the conversion price per share will be deemed to be $3.30, subject to customary anti-dilution adjustment. In addition, the holders of the Series A1 Preferred Stock will vote as a separate class with respect to certain matters, including amendments to the Company’s Articles of Incorporation that alter the voting powers, preferences and special rights of the Series A1 Preferred Stock.

Liquidation . In the event we voluntarily or involuntarily liquidate, dissolve or wind up, the holders of the Series A1 Preferred Stock will be entitled, before any distribution or payment out of our assets may be made to or set aside for the holders of any of our junior capital stock and subject to the rights of our creditors, to receive a liquidation distribution in an amount equal to $10,000 per share, plus any declared but unpaid dividends. A merger, consolidation or sale of all or substantially all of our property or business is not deemed to be a liquidation for purposes of the preceding sentence.

Redemption . The Series A1 Preferred Stock is redeemable in whole or in part at our option at any time. The redemption price is equal to $10,000 per share, plus any declared but unpaid dividends.

Preemptive Rights . Holders of the Series A1 Preferred Stock do not have preemptive right to purchase securities of the Company.

Mandatory Conversion . Each share of Series A1 Preferred Stock remaining outstanding will automatically be converted into shares of our common stock upon the earlier of (i) any closing of underwritten offering by the Company of shares of Common Stock to the public pursuant to an effective registration statement under the Securities Act of 1933, in which the aggregate cash proceeds to be received by the Company and selling stockholders (if any) from such offering (without deducting underwriting discounts, expenses and commissions) are at least $15,000,000, and the price per share paid by the public for such shares is at least $3.30 (such price to be adjusted for any stock dividends, combinations or splits or (ii) the date agreed to by written consent of the holders of a majority of the outstanding Series A1 Preferred Stock.

Optional Conversion by Investors . At any time, each holder of Series A1 Preferred Stock has the right, at such holder’s option, to convert all or any portion of such holder’s Series A1 Preferred Stock into shares of our common stock prior to the mandatory conversion of the Series A1 Preferred Stock at a price of $3.30 per share.

Optional Conversion by the Company . On or after six months from the date that the first share is issued, if the closing price of the Common Stock on the Trading Market is $4.50 or more for 20 consecutive trading days, then up to 25% of the outstanding stated value of the Series A1 Preferred Stock, plus any accrued and unpaid dividends, will be subject to conversion into Company common stock at the option of the Company. For each successive period that the closing price of the common stock is at least $4.50 for a period of 20 consecutive trading says beyond the first 20 day period, the Company will have the right to convert another 25% of the outstanding Series A1 Preferred Stock, such that if the closing price of the common stock is at least $4.50 for 80 consecutive trading days, then all of the outstanding shares of Series A1 Preferred Stock may be converted into Company common stock at the Company’s option.

Conversion Price . Each share of Series A1 Preferred Stock is convertible into shares of common stock at a conversion price of $3.30 per share, subject to customary anti-dilution adjustments, including in connection with stock dividends and distributions, stock splits, subdivisions and combinations.

Redemption by Holder. Unless prohibited by Colorado law governing the Company, upon ninety days’ prior written request from any holders of outstanding shares of Series A1 Preferred Stock, the Company may at its discretion, redeem at a redemption price equal to the sum of (i) $10,000 per share and (ii) the accrued and unpaid dividends thereon, to the redemption date, up to one-third of each holder’s outstanding shares of Series A1 Preferred Stock on: (i) the first anniversary of the Original Issuance Date (the “First Redemption Date”), (ii) the second anniversary of the Original Issue Date (the “Second Redemption Date”) and (iii) the third anniversary of the Original Issue Date (the “Third Redemption Date”, along with the First Redemption Date and the Second Redemption Date, collectively, each a “Redemption Date”).

F-14

The redemption price for any shares of Series A1 Preferred Stock shall be payable on the redemption date to the holder of such shares against surrender of the certificate(s) evidencing such shares to the Corporation or its agent. The Company may instead at its option, reduce the applicable conversion price by 50% with respect to the shares of preferred stock for which redemption has been requested.

5. Advances payable – related parties

The officers and directors of the Company have advanced funds to pay for the filing and other necessary costs of the Company. As of December 31, 2010 and 2011, the Company owed the related parties are unsecured, due on demand, and working capital advances:


	2010		2011
Advances – Donald Prosser (2)	$	220,000	$	20,000
Advances – Donald Prosser (3)		4,290		4,100
Advances – Donald Prosser (1)		215,000		—
Advances – Charles Gamber (3)		4,966		—
Advances – William Stewart (3)		20,219		20,219
Advances – William Stewart (2)		75,000		25,000
Advances – Charles Davis (2)		125,000		—
Advances – Charles Davis (2)		40,000		40,000

Balances	$	704,475	$	109,319

(1)	Donald W. Prosser pledged 215,000 shares of his Common stock to unrelated individuals in exchange for a loan to the Company of $215,000 due in May 2011. The advance was used as working capital.

(2)	$460,000 at December 31, 2010 and $85,000 at December 31, 2011 of the advances bear interest at 9.6% per annum.

(3)	$29,475 at December 31, 2010 and $24,319 at December 31, 2011 of the advances bear interest at 8.0% per annum.

The Company has related party payables of accrued interest to the officers and directors above of $ 37,121 at December 31, 2011. In addition, the Company owes an entity owned by Charles Davis, DNR Oil & Gas, Inc. The balance owed to DNR Oil & Gas, Inc. as of December 31, 2011 for expenses of $151,748 was included in accounts payable and production to the operator of $416,835 and $576,791 for the oil in tanks at April 1, 2011, also included in accounts payable $250,000 additional consideration is due to DNR for the acquisition. The Company accrued $90,000 for director fees for the second, third, and fourth quarters 2011.

6. Contracts payable

The Company had a director of the Company pay for consulting services related to the marketing of the Company, its financing and financial operations. The director paid the consultants 220,000 shares in 2010 and 100,000 shares in 2011 of his common stock of the Company in exchange for the services valued at $ 230,000. One of the contracts is for a period of one year, the fiscal year 2010, amortized over that period. The second contract is for two years beginning January 1, 2010 and will be amortized over the two year period. The unused balance of the contact is carried as prepaid expenses. The stock was repaid in equal shares during the second fiscal quarter of 2011 and was adjusted for the 100 to 1 stock reverse on a pro rata basis.

The Company owes a director for services related to the operations of the pipeline business and purchase of oil and gas properties. The board of directors agreed to pay the director on a three year contract beginning January 1, 2010 $245,000 to be paid in the form of 350,000 shares of common stock. The expense will be amortized over the life of the contract at $30,625 per quarter and the unused balance will be carried as a prepaid expense. The contract was paid in equal shares during the second fiscal quarter of 2011.

The Company entered into a consulting contract with an unrelated party for financing, structure, and investor services on March 2, 2010 for 800,000 shares of Common Stock valued at $500,000. The contract is for a period of three years and will be amortized over a thirty-six month period. The contract was paid in equal shares during the second fiscal quarter and 770,000 shares were issued in May 2011. The remaining 30,000 shares owed are valued at $ 18,750.

The Company owed its directors for services for part of 2008, 2009, 2010 and first quarter 2011. They were accruing $128,000 during fiscal 2010 and first quarter of fiscal 2011 to be paid in the future with 72,841 shares of Common Stock valued at an average of $1.76 per share. All shares were issued in May 2011.

F-15

7. Notes payable

In May 2011, the Company received proceeds from a bridge loan of $250,000 from two unrelated individuals at 12% interest. The loan is secured by shares of common stock owned by the CEO of the Company and due on August 31, 2011 and verbally extended to March 7, 2012. In July 2011, the Company received proceeds from a second bridge loan of $340,000 from three unrelated individuals at 10% interest. The loan is unsecured and due on September 30, 2011 verbally extended to November 30, 2011 the loans were paid in full in December 2011. The balance of the loans outstanding at December 31, 2011 is $250,000.

The Company secured a note for a maximum $850,000 with a stockholder. The note has an assignment of the production receivable of $981,203. The interest rate is 12% plus a processing and loan fees to be determined by the usage of the line and length of the outstanding balance. The note was paid in full at December 31, 2011.

8. Income taxes

At December 31, 2011, the Company has net operating loss (“NOL”) carryforwards for Federal income tax purposes of approximately $8,000,000. If not previously utilized, the NOL carryforwards will expire in 2015 through 2031.

For the years ended December 31, 2010 and 2011, the Company did not recognize any current or deferred income tax benefit or expense. Actual income tax benefit (expense) for the years ended December 31, 2010 and 2011 differs from the amounts computed using the federal statutory tax rate of 34%, as follows:


	2010			2011
Income tax benefit (expense) at the statutory rate	$	290,000		$	(168,000	)
Benefit (expense) resulting from:
Increase in Federal valuation allowance		(290,000	)		—
Utilization of net operating loss carryforwards		—			168,000

Income tax benefit (expense)	$	—		$	—

At December 31, 2010 and 2011, the tax effects of temporary differences that give rise to significant deferred tax assets and liabilities are presented below:


	2010			2011
Federal net operating loss carryforwards	$	2,856,000		$	2,720,000
State net operating loss carryforwards		413,000			400,000
Oil and gas properties		—			(217,000	)
Asset retirement obligations		—			222,000

Net deferred tax assets		3,269,000			3,125,000
Less valuation allowance		(3,269,000	)		(3,125,000	)

Net deferred tax assets	$	—		$	—

A valuation allowance has been recorded for all deferred tax assets since the “more likely than not” realization criterion was not met as of December 31, 2010 and 2011.

A tax benefit from an uncertain tax position may be recognized if it is “more likely than not” that the position is sustainable based solely on its technical merits. For the years ended December 31, 2010 and 2011, the Company had no unrecognized tax benefits and management is not aware of any issues that would cause a significant increase to the amount of unrecognized tax benefits within the next year. The Company’s policy is to recognize any interest or penalties as a component of income tax expense. The Company’s material taxing jurisdictions are comprised of the U.S. federal jurisdiction and the states of Colorado, Wyoming and Kansas. The tax years 2006 through 2011 remain open to examination by these taxing jurisdictions.

F-16

9. Asset retirement obligations (ARO)

A reconciliation of the Company’s asset retirement obligations for the years ended December 31, 2010 and 2011, are as follows (in thousands):


	Year Ended December 31:
	2010		2011
Beginning of year	$	—	$	—
Liabilities incurred		—		639,176
Liabilities settled		—		—
Accretion expense		—		14,064
Revisions to estimate		—		—

End of year		—		653,240
Less current asset retirement obligations		—		(15,398	)

Long-term asset retirement obligations	$	—	$	637,842

10. Commitments and contingencies

Lease commitments:

The Company entered into a lease for roads and compressor space in Wyoming for the pipeline. This commitment began in October and paid annually in April. The expense in 2010 was $9,600 and the cost in 2011 was $9,600, included in pipeline costs. Storage rent expense for the years ended December 31, 2010 and December 31, 2011 amounted to $554 and $1,079 respectively. The Company uses office space and conference room space provided by a director for $3,000 rent for the years ended December 31, 2010 and 2011.

The following is a schedule by years of minimum future rentals on non-cancelable operating leases as of December 31, 2011:


	Compressor
	Pad and Roads		End pad		Total
2012	$	2,250	$	600	$	2,850
2013		—		600		600
2014		—		600		600
2015		—		600		600
2016		—		600		600
Thereafter		—		3,300		3,300

Total minimum future rentals	$	2,250	$	6,300	$	8,550

11. Discontinued operations

The Company’s decision to pursue projects and investments in oil and natural gas exploration and production required that it formally discontinue its former operations beginning August 1, 2003. This decision is reflected by a change in the presentation of the Company’s financial statements to segregate discontinued operating results in previous periods from continuing operations going forward. There is no effect in the current three month period or nine month period of this reclassification.

During 2003, the Company abandoned the development of an inactive subsidiary. At December 31, 2011, the remaining liabilities of this division of $111,690 in unpaid payroll taxes, other payables, and possible penalties has been included as relief of debt income and there is no remaining liability.

12. Business and Credit Concentrations

Concentrations of Market Risk. The future results of the Company’s oil and gas operations will be affected by the market prices of oil and gas. A readily available market for crude oil, natural gas and liquid products in the future will depend on numerous factors beyond the control of the Company, including weather, imports, marketing of competitive fuels, proximity and capacity of oil and gas pipelines and other transportation facilities, any oversupply or undersupply of oil, gas and liquid products, the regulatory environment, the economic environment and other regional and political events, none of which can be predicted with certainty.

F-17

The Company operates in the exploration, development and production phase of the oil and gas industry. Its receivables include amounts due from DNR Oil & Gas, Inc. (“DNR”), a related party that operates the Company’s oil and gas properties and collects remittances from the purchasers of the Company’s oil and natural gas. The Company believes that no single customer or joint venture partner exposes the Company to significant credit risk. While certain of these customers and joint venture partners are affected by periodic downturns in the economy in general or in their specific segment of the natural gas or oil industry, the Company believes that its level of credit-related losses due to such economic fluctuations has been and will continue to be immaterial to the Company’s results of operations in the long-term. Trade receivables are not collateralized.

Concentrations of Credit Risk. The Company maintains its cash in bank accounts that, at times, may exceed federally insured limits. At December 31, 2011, the Company had approximately $793,000 of cash in bank accounts that exceeded the $250,000 federally insured limit. The difference between this amount and the amount of cash and equivalents shown in the 2011 consolidated balance sheets is primarily attributable to outstanding checks. The Company has not experienced any losses related to investments in cash and equivalents.

13. Pro-Forma information acquisition (unaudited)

The table below reflects unaudited pro forma results as if the acquisition of oil and gas properties had taken place as of January 1, 2010:


	2010			2011
Total revenue	$	2,254,564		$	2,756,294

Net income (loss)	$	(1,712,241	)	$	458,553

Net income (loss) applicable to common stockholders	$	(1,712,241	)	$	262,553

Earnings per share:
Basic	$	(0.35	)	$	0.04

Diluted	$	(0.35	)	$	0.04

The unaudited pro forma data gives effect to the actual operating results of the acquired properties prior to the acquisition, adjusted to include the pro forma effect of depreciation, depletion, amortization and accretion based on the purchase price of the properties. The unaudited pro forma results exclude the operating results for the School Creek property that was acquired on July 29, 2011 and sold on August 23, 2011 as discussed further in Note 3. Other pro forma adjustments eliminated gas gathering production costs payable to DNR due to our purchase of the Buff field, and to increase expenses by $15,000 per month for administrative costs incurred under an Operating Agreement with DNR that was effective on October 1, 2011. Pro forma adjustments were recognized to record interest expense on $10.1 million of seller financing from January 1, 2010 through July 29, 2011.

14. Subsequent events

The Company sold a working interest in a well and related lease in Niobrara County Wyoming of its recently acquired assets for approximately $1.1 million to an unaffiliated party. Arête paid $144,682 in the original purchase price for a 50% working interest and an overriding royalty interest. In October 2011, Arête purchased the remaining 50% working interest and an overriding royalty interest for $168,420. Therefore, Arête’s gain on the sale is approximately $750,000 is expected to be recognized in the first quarter of 2012, and it retains its 2.575% overriding royalty interest.

F-18

15. Supplementary Oil and Gas Information (unaudited)

Costs Incurred. Costs incurred in oil and gas property acquisition (including the School Creek property described in Note 3), exploration and development activities and related depletion per equivalent unit-of-production were as follows:


	2010		2011
Acquisition costs:
Unproved properties	$	—	$	132,945
Proved properties		—		8,321,638
School Creek property		—		2,621,113
Exploration costs		—		—
Development costs		—		—
Asset retirement obligations		—		639,176

Total costs incurred	$	—	$	11,714,872

Depletion per BOE of production	$	—	$	22.72

Supplemental Oil and Gas Reserve Information

The reserve information presented below is based on estimates of net proved reserves as of December 31, 2011 that were prepared by the Company’s independent petroleum engineering firm, Ryder Scott Company, in accordance with guidelines established by the SEC.

Proved oil and gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., prices and costs as of the date the estimate is made). Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Changes in Proved Reserves

The Company did not have any proved reserves prior to 2011. The following table sets forth information regarding the Company’s estimated total proved and oil and gas reserve quantities (excluding the School Creek property described in Note 3) for the year ended December 31, 2011:


	Oil (Bbl)			Gas (Mcf)			Equivalent (BOE)
Balance, December 31, 2010		—			—			—
Purchase of oil and gas reserves in place		385,008			865,778			529,305
Production		(9,990	)		(38,477	)		(16,403	)

Balance, December 31, 2011		375,018			827,301			512,902

Proved reserves, December 31, 2011:
Proved developed		290,038			604,476			390,784

Proved undeveloped		84,980			222,825			122,118

Standardized Measure

Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. The Company believes such information is essential for a proper understanding and assessment of the data presented.

Future cash inflows are computed by applying the SEC-mandated 12 month arithmetic average of the first of month price for January through December 31, 2011, which resulted in benchmark prices of $96.19 per barrel for crude oil and $4.12 per MMbtu for natural gas. Prices were further adjusted for transportation, quality and basis differentials, which resulted in an average price used as of December 31, 2011 of $83.79 per barrel of oil and $5.84 per Mcf for natural gas.

The assumptions used to compute estimated future cash inflows do not necessarily reflect the Company’s expectations of actual revenues or costs, nor their present worth. In addition, variations from the expected production rate also could result directly or indirectly from factors outside of the Company’s control, such as unexpected delays in development, changes in prices or regulatory or environmental policies. The reserve valuation further assumes that all reserves will be disposed of by production. However, if reserves are sold in place, additional economic considerations could also affect the amount of cash eventually realized.

F-19

Future development and production costs are 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 are computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pre-tax net cash flows relating to the Company’s proved oil and gas reserves. Permanent differences in oil and gas related tax credits and allowances are recognized.

A 10% annual discount rate was used to reflect the timing of the future net cash flows relating to proved oil and gas reserves.

The following table presents the standardized measure of discounted future net cash flows related to proved oil and gas reserves as of December 31, 2011:


Future cash inflows	$	36,256,572
Future production costs		(14,467,156	)
Future development costs		(964,486	)
Future income taxes		(4,687,201	)

Future net cash flows		16,137,729
10% annual discount		(7,795,729	)

Standardized measure of discounted future net cash flows	$	8,342,000

The present value (at a 10% annual discount) of future net cash flows from the Company’s proved reserves is not necessarily the same as the current market value of its estimated oil and gas reserves. The Company bases the estimated discounted future net cash flows from its proved reserves on average prices realized in the preceding year and on costs in effect at the end of the year. However, actual future net cash flows from the Company’s oil and gas properties will also be affected by factors such as actual prices the Company receives for oil and gas, the amount and timing of actual production, supply of and demand for oil and gas and changes in governmental regulations or taxation.

The timing of both the Company’s production and incurrence of expenses in connection with the development and production of oil and gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% annual discount factor the Company uses when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company or the oil and gas industry in general.

A summary of changes in the standardized measure of discounted future net cash flows is as follows for the year ended December 31, 2011:


Standardized measure of discounted future net cash flows, beginning of year	$	—
Sales of oil and gas, net of production costs and taxes		(440,596	)
Changes in estimated future development costs		(918,376	)
Purchases of reserves in place		15,846,975
Sales of reserves in place		(3,622,558	)
Net changes in future income taxes		(2,523,445	)

Standardized measure of discounted future net cash flows, end of year	$	8,342,000

F-20

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED BALANCE SHEETS

December 31, 2011 and June 30, 2012


	2011			2012
ASSETS
Current Assets:
Cash and equivalents	$	219,566		$	168,241
Receivable from DNR Oil & Gas, Inc.:
Oil and gas sales, net of production costs		165,283			106,957
Other		15,597			38,444
Prepaid expenses and other		207,338			147,874

Total Current Assets		607,784			461,516

Property and Equipment:
Oil and gas properties, at cost, successful efforts method:
Proved properties		9,056,032			9,219,558
Unevaluated properties		287,728			310,288
Natural gas gathering system		442,195			442,195
Furniture and equipment		22,522			22,522

Total property and equipment		9,808,477			9,994,563
Less accumulated depreciation, depletion and amortization		(525,154	)		(876,551	)

Net Property and Equipment		9,283,323			9,118,012

TOTAL ASSETS	$	9,891,107		$	9,579,528

The Accompanying Notes are an Integral Part of These Financial Statements.

F-21

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED BALANCE SHEETS, Continued

December 31, 2011 and June 30, 2012


	2011			2012
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable:
Payable to DNR Oil & Gas, Inc.:
Oil and gas property acquisition costs	$	826,791		$	291,616
Gas gathering operating costs		416,835			436,403
Operator fees and other		151,748			151,748
Unrelated parties		92,019			96,912
Notes and advances payable:
Directors and affiliates		109,319			245,950
Unrelated parties		250,000			250,000
Accrued interest expense		88,303			39,375
Director fees payable in common stock		90,000			30,000
Accrued consulting services payable in common stock		18,750			48,750
Current portion of asset retirement obligations		15,398			67,527
Other accrued costs and expenses		216,061			258,040

Total Current Liabilities		2,275,224			1,916,321

Long-Term Liabilities:
Acquisition costs payable to DNR Oil & Gas, Inc.		—			250,000
Asset retirement obligations, net of current portion		637,842			599,840

Total Long-Term Liabilities		637,842			849,840

Total Liabilities		2,913,066			2,766,161

Commitments and Contingencies (Note 3, 5 and 9)

Stockholders’ Equity:
Convertible Class A preferred stock; $10,000 face value per share, authorized 1,000,000 shares:
Series 1; authorized 30,000 shares, issued and outstanding 522.5 shares in 2011 and 2012, liquidation preference of $5,420,938 in 2011 and 2012		5,023,371			5,023,371
Series 2; authorized 2,500 shares, no shares issued and outstanding in 2011 and 2012		—			—
Common stock, no par value; authorized 499,000,000 shares, issued and outstanding 7,764,476 in 2011 and 7,979,803 in 2012		16,904,154			17,151,096
Accumulated deficit		(14,949,484	)		(15,361,100	)

Total Stockholders’ Equity		6,978,041			6,813,367

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	9,891,107		$	9,579,528

The Accompanying Notes are an Integral Part of These Financial Statements.

F-22

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS

Six-Months Ended June 30, 2011 and 2012


	2011			2012
Revenues:
Oil and natural gas sales	$	—		$	1,035,395
Sale of oil and natural gas properties		—			533,048
Gas gathering income		45,639			—

Total revenues		45,639			1,568,443

Operating Expenses:
Oil and gas producing activities:
Lease operating expenses		—			401,653
Production taxes		—			84,326
Depreciation, depletion, amortization and accretion		—			336,837
Gas gathering:
Cost of operations:
Related Party		30,815			—
Unrelated parties		80,558			7,320
Depreciation		22,110			22,110
General and administrative expenses:
Director fees		60,000			60,000
Investor relations		225,322			130,031
Acquisition investigation and due diligence		500,478			—
Legal, auditing and professional services		85,969			77,642
Consulting and executive services:
Related parties		112,750			316,500
Unrelated parties		161,852			76,504
Other administrative expenses		25,695			42,795
Depreciation		—			285

Total operating expenses		1,305,549			1,556,003

Operating income (loss)		(1,259,910	)		12,440
Other income (expense):
Interest income		279			220
Interest expense		(34,442	)		(32,401	)

Loss before income taxes		(1,294,073	)		(19,741	)
Income tax benefit (expense)		—			—

Net loss	$	(1,294,073	)	$	(19,741	)

Net Loss Applicable to Common Stockholders:
Net loss	$	(1,294,073	)	$	(19,741	)
Accrued preferred stock dividends		—			(391,875	)

Net loss applicable to common stockholders	$	(1,294,073	)	$	(411,616	)

Earnings (Loss) Per Share Applicable to Common Stockholders:
Basic	$	(0.22	)	$	(0.05	)

Diluted	$	(0.22	)	$	(0.05	)

Weighted Average Number of Common Shares Outstanding:
Basic		5,995,000			7,776,000

Diluted		5,995,000			7,776,000

The Accompanying Notes are an Integral Part of These Financial Statements.

F-23

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

Six-Months Ended June 30, 2012


	Class A Preferred Stock				Common Stock				Accumulated
	Shares		Amount		Shares		Amount		Deficit			Total
Balances, December 31, 2011		522.5	$	5,023,371		7,764,476	$	16,904,154	$	(14,949,484	)	$	6,978,041

Issuance of common stock for
Board of Directors’ fees		—		—		65,605		120,000		—			120,000
Issuance of common stock to related parties for consulting services		—		—		135,972		110,000		—			110,000
Issuance of common stock to unrelated parties:
For accrued interest		—		—		7,750		10,462		—			10,462
For consulting services		—		—		6,000		6,480		—			6,480
Preferred stock dividends declared		—		—		—		—		(391,875	)		(391,875	)
Net loss		—		—		—		—		(19,741	)		(19,741	)

Balances, June 30, 2012		522.5	$	5,023,371		7,979,803	$	17,151,096	$	(15,361,100	)	$	6,813,367

The Accompanying Notes are an Integral Part of These Financial Statements.

F-24

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS

Six-Months Ended June 30, 2011 and 2012


	2011			2012
Cash Flows from Operating Activities:
Net loss	$	(1,294,073	)	$	(19,741	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		22,110			355,132
Accretion of discount on asset retirement obligations		—			4,100
Gain on sale of oil and gas properties		—			(533,048	)
Common stock issued in exchange for services		734,084			246,942
Common stock issued in exchange for accrued interest		—			10,462
Changes in operating assets and liabilities:
Accounts receivable		11,832			(76,179	)
Prepaid expenses and other		—			60,714
Accounts payable		(5,721	)		24,461
Accrued costs and expenses		72,991			2,590

Net cash provided by (used in) operating activities		(458,777	)		75,433

Cash Flows from Investing Activities:
Capital expenditures for oil and gas properties		(500,000	)		(646,269	)
Proceeds from sale of oil and gas properties		—			1,108,709
Contingent consideration paid to DNR under sharing arrangement		—			(282,704	)

Net cash provided by (used in) investing activities		(500,000	)		179,736

Cash Flows from Financing Activities:
Proceeds from notes and advance payable		870,000			400,000
Principal payments on notes payable		(9,256	)		(264,619	)
Payment of dividends on preferred stock		—			(391,875	)
Proceeds from sale of common stock		103,500			—
Payment of preferred stock offering costs		—			(50,000	)

Net cash provided by (used in) financing activities		964,244			(306,494	)

Net increase (decrease) in cash and equivalents		5,467			(51,325	)
Cash and equivalents, beginning of period		15,990			219,566

Cash and equivalents, end of period	$	21,457		$	168,241

Supplemental Disclosure of Cash Flow Information:
Cash paid for interest	$	17,755		$	83,827

Cash paid for income taxes	$	—		$	—

Supplemental Disclosure of Non-cash Investing and Financing Activities:
Conversion of notes payable to 897,500 shares of common stock	$	1,335,000		$	—

Advances from officers and directors, and prepaid fees to consultants paid by the issuance of common stock	$	1,019,667		$	—

Payable to DNR for acquisition of oil and gas properties	$	—		$	291,616

Asset retirement obligations assumed upon sale of oil and gas properties	$	—		$	16,411

Increase in oil and gas properties due to revision of asset retirement obligations	$	—		$	26,437

The Accompanying Notes are an Integral Part of These Financial Statements.

F-25

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2012

1. Organization and Nature of Operations

Arête Industries, Inc. (“Arête” or the “Company”), is a Colorado corporation that was formed on July 21, 1987. The Company has two wholly-owned subsidiaries which have no assets, liabilities or operations. The Company has operated a natural gas gathering system in Wyoming since 2006 and during the third quarter of 2011, the Company purchased oil and natural gas properties in Colorado, Montana, Kansas, and Wyoming from DNR Oil & Gas, Inc. (“DNR”), an affiliate of an officer and member of the Company’s board of directors. The consolidated financial statements of the Company include the accounts of the Company and its subsidiaries. All intercompany accounts have been eliminated in the consolidation.

The Company’s focuses on acquiring interests in traditional oil and gas ventures, and seeking properties that offer profit potential from overlooked and by-passed reserves of oil and natural gas, which may include shut-in wells, in-field development, stripper wells, re-completion and re-working projects. In addition, the Company’s strategy includes purchase and sale of acreage prospective for oil and natural gas and seeking to obtain cash flow from sale, drilling opportunities, and royalty income from such prospects.

2. Summary of Significant Accounting Policies

Basis of presentation

The accompanying unaudited consolidated financial statements have been prepared by the Company. In the opinion of management, the accompanying unaudited financial statements contain all adjustments (consisting of only normal recurring accruals) necessary for a fair presentation of the financial position as of December 31, 2011 and June 30, 2012, and the results of operations, changes in stockholders’ equity, and cash flows for the six-months ended June 30, 2011 and 2012. Operating results for the interim periods presented are not necessarily indicative of the results that may be expected for a full year. The Company’s annual audited consolidated financial statements included elsewhere herein include a summary of significant accounting policies that should be read in conjunction with these unaudited financial statements. Except as disclosed herein, there have been no material changes to the information disclosed in the notes to the consolidated financial statements included in the Company’s 2011 audited consolidated financial statements.

Use of estimates

Preparation of the Company’s financial statements in accordance with U.S. generally accepted accounting principles (“GAAP”) requires management to make various assumptions, judgments and estimates that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts initially established.

The most significant areas requiring the use of assumptions, judgments and estimates relate to the volumes of natural gas and oil reserves used in calculating depreciation, depletion and amortization (“DD&A”), the amount of expected future cash flows used in determining possible impairments of oil and gas properties and the amount of future capital costs used in these calculations. Assumptions, judgments and estimates also are required in determining future asset retirement obligations, impairments of undeveloped properties, and in valuing share-based payment awards. During the second quarter of 2012, the Company revised its estimates for plugging and abandonment costs and reduced its estimates of proved oil and gas reserves for certain wells that the Company intends to plug and abandon. The aggregate impact of these changes resulted in an increase in our DD&A expense of approximately $74,000 for the first six-months of 2012.

F-26

Reclassifications

The Company has condensed certain line items within the current period financial statements, and certain prior period balances were reclassified to conform to the current year presentation. Reclassifications did not have any impact on the Company’s previously reported working capital, results of operations or cash flows.

Earnings per share

Basic net income (loss) per share of common stock is calculated by dividing net income (loss) attributable to common stockholders by the weighted average number of common shares outstanding during each period. Diluted net income (loss) attributable to common stockholders is calculated by dividing net income (loss) attributable to common stockholders by the weighted average number of common shares outstanding and other dilutive securities. The only potentially dilutive securities for the diluted earnings per share calculations consist of Series 1 preferred stock that is convertible into common stock at an exchange price of $3.30 per common share. As of June 30, 2012, the convertible preferred stock had an aggregate liquidation preference of $5,420,938 and was convertible to 1,642,708 shares of common stock. These shares were excluded from the earnings per share calculation because it was anti-dilutive to assume conversion at the beginning of the period, which would have eliminated preferred dividends from the earnings per share calculation.

New Accounting Pronouncements

In May 2011, the Financial Accounting Standards Board (“FASB”) issued new fair value measurement authoritative accounting guidance clarifying the application of fair value measurement and disclosure requirements and changes particular principles or requirements for measuring fair value. This authoritative accounting guidance is effective for interim and annual periods beginning after December 15, 2011. Based on the Company’s current operations and structure, the adoption of this standard did not have an impact on the Company’s 2012 financial statements.

3. Acquisitions and Disposition of Oil and Gas Properties

Acquisitions

On May 25, 2011, the Company entered into a Purchase and Sale Agreement and other related agreements and documents with the Tucker Family Investments, LLLP, DNR Oil & Gas, Inc. (“DNR”), and Tindall Operating Company (collectively, the “Sellers”) for the purchase of certain oil and gas operating properties in Colorado, Kansas, Wyoming, and Montana (collectively, the “Original Purchase and Sale Agreement”). DNR is principally owned by an officer and director of the Company, Charles B. Davis. The consideration for the purchase was determined by bargaining between management of the Company and Sellers, and the Company used reports of independent engineering firms to analyze the purchase price. The base purchase price for the properties was $10.0 million, of which the Company paid a nonrefundable down payment of $0.5 million and the remaining $9.5 million was financed by the Sellers pursuant to a promissory note due July 1, 2011. The Company was unable to arrange the funding to pay the $9.5 million promissory note due on July 1, 2011, and therefore, the note was not paid.

F-27

remaining principal balance of the base purchase price in the amount of $10.1 million, together with interest at 10% per annum, was payable to Sellers in three monthly payments, with $3.7 million due August 15, 2011 (extended to August 31, 2011), and $3.2 million due on each of September 15, 2011 and October 15, 2011. By September 29, 2011, all required consideration had been paid to Sellers and closing of the PSA was completed.

The PSA provided that the Company was entitled to the Properties’ oil and gas production and sales proceeds beginning on April 1, 2011, and the Company was also responsible for the lease operating expenses of the Properties beginning on April 1, 2011. The net proceeds from oil and gas sales, less production taxes and lease operating expenses from April 1, 2011 to July 29, 2011 amounted to $766,728, which was treated as a reduction of the carrying costs of the Properties.

The acquisition of the Properties was structured whereby the Company acquired 100% of Seller’s interest in certain geologic zones of the properties. Presented below is a summary of agreed-upon values associated with the Properties and the Separate Interests, along with a discussion of the interests in the Properties retained by the Sellers:


*Properties:*
Rex Lake/ Big Hollow (WY)	$	511,025	*(b)*
Kansas		2,152,216	*(a)*
Montana		98,179	*(b)*
Wyoming		2,733,773	*(b)*
Buff (WY)		611,211	*(b)*
Colorado		2,507,678	*(a)*

Total Working Interest Properties		8,614,082
*Separate Interests*		2,385,918	*(d)*

	$	11,000,000	*(c)*

(a)

For a period of ten years after the closing date, the Colorado and Kansas properties provide for additional consideration that is payable to Sellers based on increases in Nymex prices for oil and natural gas, without regard to changes in the Company’s oil and natural gas reserves (referred to as the “Price Increase Factor”). If Nymex thresholds of $90, $100, $110, $125 and $150 per barrel of oil are exceeded for periods of 61 consecutive days, incremental purchase consideration of $250,000, $250,000, $500,000, $500,000 and $2,000,000, respectively, will be payable to Sellers. Similarly, if Nymex thresholds of $5.00, $6.00, $7.50, $10.00 and $12.00 per MMbtu of natural gas are exceeded for periods of 61 consecutive days, incremental purchase consideration of $50,000, $50,000, $150,000, $250,000 and $250,000, respectively, will be payable to Sellers.

(b)

F-28

The maximum increase in purchase price (including Sellers retained interest of 70% for the Wyoming properties discussed in the preceding paragraph) for all properties in all states shown in the table above is limited to $25 million. Due to the sale of the Separate Interests discussed below, accrual of $500,000 due to a sustained increase in oil prices over $90 and $100 per barrel, and the sale of a second property in February 2012, the maximum future consideration has been reduced by approximately $5.2 million to $19.8 million.

(c)

(d)

With respect to the Separate Interests, a formal closing and transfer of title was not required, and did not occur, in order for the Company to realize its proceeds related to the sale of the Separate Interests. The Company acquired the contractual rights associated with the Separate Interests on July 29, 2011, and the Company’s share of the net proceeds of $5,101,047 was received on August 23, 2011, which resulted in recognition of a non-operating gain in the third quarter of 2011 of $2,479,934. The Company applied the $5,101,047 of net proceeds to the payments due under the PSA.

The table below reflects unaudited pro forma results as if the third quarter of 2011 acquisition of oil and gas properties had taken place as of January 1, 2011:


	Six Months Ended June 30, 2011:
	Historical			Pro Forma
Total revenue	$	45,639		$	1,542,954

Net income (loss)	$	(1,294,073	)	$	(1,355,901	)

Net income (loss) applicable to common stockholders	$	(1,294,073	)	$	(1,355,901	)

Earnings per share:
Basic	$	(0.22	)	$	(0.23	)

Diluted	$	(0.22	)	$	(0.23	)

Property Disposition

In February 2012, the Company sold to an unaffiliated party a working interest in a well and related lease in Niobrara County, Wyoming for gross proceeds of approximately $1,109,000. After payment of additional consideration pursuant to

F-29

the formula discussed under (b) in the acquisition table above, the Company realized net proceeds of $826,000. The purchaser assumed the asset retirement obligations estimated at approximately $16,000 and after deducting the net book value of the property, the Company recognized a gain on sale of $533,048. The Company retained a 2.575% overriding royalty interest in this property. This sale comprised approximately 1.6% of the Company’s barrels of oil equivalent (“BOE”) of oil and gas reserve quantities, and approximately 2.2% of the Company’s discounted future net revenues prior to the sale. The Company determined that this sale did not qualify for discontinued operations reporting. This gain on sale is included in operating revenues in the unaudited consolidated statement of operations for the six-months ended June 30, 2012.

4. Income Taxes

The book to tax temporary differences resulting in deferred tax assets and liabilities are primarily net operating loss carry forwards of approximately $8.2 million which expire in 2015 through 2031. A 100% valuation allowance has been established against the deferred tax assets, as utilization of the loss carry forwards and realization of other deferred tax assets cannot be reasonably assured.

5. Stockholders’ Equity

Common Stock Issuances

In June 2012, the Company issued an aggregate of 215,327 shares of common stock in satisfaction of previously accrued liabilities as follows:


	Number of Shares		Valuation Price		Amount
Board of Director fees:
Fees for second quarter of 2011		5,769	$	5.20	$	30,000
Fees for third quarter of 2011		10,000	$	3.00		30,000
Fees for fourth quarter of 2011		22,058	$	1.36		30,000
Fees for first quarter of 2012		27,778	$	1.08		30,000
Related party executive, administrative & operational services
Fees for January 2012		11,538	$	1.30		15,000
Fees for February 2012		12,500	$	1.20		15,000
Fees for March 2012		13,890	$	1.08		15,000
Fees for April 2012		13,044	$	1.15		15,000
Related party consulting services in June 2012		85,000	$	0.59		50,000
Accrued interest on unrelated party notes payable		7,750	$	1.35		10,462
Unrelated party consulting		6,000	$	1.08		6,480

Total		215,327	$	0.59	$	246,942

Board of Directors fees are payable quarterly in common stock based on the closing price at the end of each quarter. Each of the Company’s five directors earns a monthly fee of $2,000 for an aggregate of $30,000 per quarter. In June 2012, an aggregate of 65,605 shares were issued for director fees incurred in the second quarter of 2011 through the first quarter of 2012.

Effective January 1, 2012, the Board of Directors agreed to pay fees for executive, administrative and operational services in the aggregate amount of $15,000 per month to three individuals who are directors and/or stockholders of the Company. These fees are payable in shares of the Company’s common stock based on the closing price on the last day of the month for which the services are performed. In June 2012, the Company issued an aggregate of 50,972 shares of common stock in satisfaction of this obligation for the months of January through April 2012.

In June 2012, the Board of Directors approved the issuance of 85,000 shares of common stock for consulting services provided by an individual that owns preferred stock of the Company. The services were valued based on the closing price of the Company’s common stock on the date of board approval which was $0.59 and resulted in a charge to related party consulting fees of $50,000.

As of June 30, 2012, the Company has a liability for directors’ fees of $30,000 which is expected to result in the issuance of 55,555 shares of common stock in the third quarter of 2012. Additionally, the Company has a liability for accrued consulting fees of $48,750 which is expected to result in the issuance of 74,823 shares of common stock in the third quarter of 2012.

F-30

Preferred Stock Dividends

On March 30, 2012 the Board of Directors declared the 15% dividend on the Series A-1 preferred stock which was paid in cash on April 2, 2012. As of June 30, 2012, accrued and undeclared dividends amounted to $195,938. Preferred stock dividends are payable semi-annually in cash or shares of the Company’s common stock, at the election of the Company. The next dividend payment date is on September 30, 2012.

6. Contracts Payable

The Company entered into a consulting contract for financing, structure, and investor services on March 2, 2010 for 800,000 shares of Common Stock valued at $500,000. The contract is for a period of three years and is being amortized ratably over the service period. For the quarters ended June 30, 2011 and 2012, $41,667 related to this consulting contract is included in investor relations expense in the accompanying unaudited consolidated statements of operations. For the six-months ended June 30, 2011 and 2012, $83,333 related to this consulting contract is included in investor relations expense in the accompanying unaudited consolidated statements of operations. As of June 30, 2012, the unamortized balance of approximately $111,000 is included in prepaid expenses and other in the accompanying unaudited consolidated balance sheet.

7. Notes and Advances Payable

Notes and advances payable consist of the following as of December 31, 2011 and June 30, 2012:


	2011		2012
Officers, directors and affiliates:
Notes and advances payable, interest at 8.0%, due on demand	$	24,319	$	10,950
Notes and advances payable, interest at 9.7%, due on demand		85,000		85,000
Note payable, interest at 12.0%, due March 2013		—		150,000

Total officers, directors and affiliates		109,319		245,950

Unrelated parties:
Note payable, interest at 12.0%, due March 2013		—		250,000
Notes payable, interest at 12.0%, due March 2012		250,000		—

Total unrelated parties		250,000		250,000

Total notes and advance payable	$	359,319	$	495,950

All of the notes payable shown above are unsecured. Accrued interest on notes and advances payable amounted to $88,303 as of December 31, 2011 and $39,375 as of June 30, 2012.

8. Asset Retirement Obligations

The Company follows accounting for asset retirement obligations in accordance with ASC 410, Asset Retirement and Environmental Obligations , which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it was incurred if a reasonable estimate of fair value can be made. The Company’s asset retirement obligations primarily represent the estimated present value of the amounts expected to be incurred to plug, abandon and remediate producing and shut-in wells at the end of their productive lives in accordance with applicable state and federal laws. The Company determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to plugging and abandonment liabilities. The significant inputs used to calculate such liabilities include estimates of costs to be incurred; the Company’s credit adjusted discount rates, inflation rates and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period and the capitalized asset retirement costs are amortized using the unit of production method.

F-31

A reconciliation of the Company’s asset retirement obligations (“ARO”) for the six-months ended June 30, 2012, is as follows:


Balance, December 31, 2011	$	653,240
Liabilities paid		—
Liabilities assumed by buyer of properties		(16,411	)
Accretion expense		4,101
Revisions of prior estimates		26,437

Balance, June 30, 2012		667,367
Less current asset retirement obligations		(67,527	)

Long-term asset retirement obligations	$	599,840

9. Related Party Operator Agreement

In connection with the acquisition agreement entered into in the third quarter of 2011, the Company executed an operating agreement whereby DNR provides services to operate all of the properties acquired by the Company for a monthly fee of $23,000. The operating agreement expired on March 31, 2012 and renews on a month to month basis. Based on operator costs for the properties prior to the Company’s acquisition, approximately $8,000 per month is included in lease operating expenses and $15,000 per month is included in related party consulting fees in the accompanying unaudited consolidated statements of operations.

10. Subsequent events

In July 2012, the owner of the natural gas gathering system that the Company uses to transport production from its Colorado natural gas properties notified the Company that it is undertaking a program to significantly expand its gathering and processing capacity. While the long-term impact of this program may be somewhat favorable, the near term impact will likely be service interruptions and curtailments that could have an adverse impact on the Company’s future natural gas sales. During April and June 2012, the Company received “force majeure” notices about service interruptions and curtailments that impacted the Colorado properties. Natural gas production for the Colorado properties was approximately 15% lower in the second quarter of 2012 compared to the first quarter of 2012.

On September 29, 2012, the Company borrowed $455,000 under a note agreement that provides for interest at an annual rate of 12% with unpaid principal and interest due on March 29, 2013. The Company also agreed to assign 75% of its operating income from its oil and gas operations and any lease or well sale or any other asset sales to the Note Holder to secure the debt. The Note Holder is 100% owned by a consultant and shareholder of the Company. The Company also paid a loan fee of $2,700 and prepaid interest of $27,300 on the Note, resulting in net proceeds of $420,000.

On September 11, 2012 the Board of Directors declared the 15% dividend on the Series A-1 preferred stock which was paid in cash in the approximate amount of $392,000 on October 1, 2012.

F-32

CAUSEY DEMGEN & MOORE P.C.

1125 Seventeenth Street, Suite 1450

Denver, Colorado 80202

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors

Arête Industries, Inc.

Westminster, Colorado

We have audited the accompanying statements of operating revenues and direct operating expenses (the “Statements”) of the oil and gas working interests acquired by Arête Industries, Inc. for the years ended December 31, 2009 and 2010. The Statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Statements based on our audits.

We conducted our audits in accordance with 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 Statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall statement presentation. We believe that our audits provide a reasonable basis for our opinion.

The accompanying Statements are prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission as described in Note 2 and are not intended to be a complete presentation of the Properties’ revenues and expenses.

In our opinion, the Statements referred to above present fairly, in all material respects, the operating revenues and direct operating expenses of the oil and gas working interests acquired by Arête Industries, Inc. for the years ended December 31, 2009 and 2010 in conformity with accounting principles generally accepted in the United States of America.

/s/ Causey Demgen & Moore P.C.

Denver, Colorado

October 12, 2012

F-33

STATEMENTS OF OPERATING REVENUES AND DIRECT OPERATING EXPENSES

OF OIL & GAS WORKING INTERESTS ACQUIRED BY ARÊTE INDUSTRIES, INC.

(EXCLUDING THE “SEPARATE INTERESTS” DESCRIBED IN NOTE 1)


	Year Ended December 31:				Six Months Ended June 30:
	2009		2010		2010		2011
					(Unaudited)		(Unaudited)
Operating Revenues:
Oil sales	$	1,364,161	$	1,568,153	$	744,017	$	1,206,498
Natural gas sales		402,445		518,785		271,884		290,817

Total operating revenues		1,766,606		2,086,938		1,015,901		1,497,315

Direct Operating Expenses
Lease operating expense		1,147,813		1,172,340		566,240		560,649
Production taxes		153,703		167,742		80,380		121,183

Total direct operating expenses		1,301,516		1,340,082		646,620		681,832

Operating Revenues in Excess Of Direct Operating Expenses	$	465,090	$	746,856	$	369,281	$	815,483

The Accompanying Notes are an Integral Part of These Statements of Operating Revenues and Direct Operating Expenses.

F-34

NOTES TO STATEMENTS OF OPERATING REVENUES

AND DIRECT OPERATING EXPENSES

1.	SUMMARY OF ACQUISITION AGREEMENT :

On May 25, 2011, Arête Industries, Inc. (the “Company”) entered into a Purchase and Sale Agreement and other related agreements and documents with the Tucker Family Investments, LLLP, DNR Oil & Gas, Inc. (“DNR”), and Tindall Operating Company (collectively, the “Sellers”) for the purchase of certain oil and gas operating properties in Colorado, Kansas, Wyoming, and Montana (collectively, the “Original Purchase and Sale Agreement”). DNR is principally owned by a director of the Company, Charles B. Davis. The consideration for the purchase was determined by bargaining between management of the Company and Sellers, and the Company used reports of independent engineering firms to analyze the purchase price. The base purchase price for the properties was $10.0 million, of which the Company paid a nonrefundable down payment of $0.5 million and the remaining $9.5 million was financed by the Sellers pursuant to a promissory note due July 1, 2011. The Company was unable to arrange the funding to pay the $9.5 million promissory note due on July 1, 2011, and therefore, the note was not paid.

On July 29, 2011, the Company and Sellers entered into an Amended and Restated Purchase and Sale Agreement (“PSA”) regarding the purchase of (i) working interests in oil and gas properties located in Wyoming, Colorado, Kansas and Montana (referred to as the “Properties”), and (ii) vested contractual rights in the net proceeds from the future sale of certain properties located in Wyoming (referred to as the “Separate Interests”). The material terms of the PSA included an aggregate base purchase price for the Properties and the Separate Interests of $11.0 million to be paid by an initial payment of $0.9 million, comprised of (i) a credit in the amount of $0.5 million previously paid by the Company in connection with the Original Purchase and Sale Agreement; and (ii) $0.4 million in funds paid contemporaneously with the execution of the PSA. The remaining principal balance of the base purchase price in the amount of $10.1 million, together with interest at 10% per annum, was payable to Sellers in three monthly payments, with $3.7 million due August 15, 2011 (extended to August 31, 2011), and $3.2 million due on each of September 15, 2011 and October 15, 2011. By September 29, 2011, all required consideration had been paid to Sellers and closing was completed.

The PSA provided that the Company was entitled to proceeds from the production of oil and gas beginning on April 1, 2011, and the Company was also responsible for the lease operating expenses beginning on April 1, 2011. The net proceeds from oil and gas sales, less production taxes and lease operating expenses from April 1, 2011 to July 29, 2011 amounted to $628,260 for the Properties and $138,468 for the Separate Interests for an aggregate of $766,728. These amounts were treated as a reduction of the carrying costs of the Properties and the Separate Interests.

F-35


*Properties:*
Rex Lake/ Big Hollow (WY)	$	511,025	*(b)*
Kansas		2,152,216	*(a)*
Montana		98,179	*(b)*
Wyoming		2,733,773	*(b)*
Buff (WY)		611,211	*(b)*
Colorado		2,507,678	*(a)*

Total Working Interest Properties		8,6142,082
*Separate Interests*		2,385,918	*(d)*

	$	11,000,000	*(c)*

(a)

For a period of ten years after the closing date, the Colorado and Kansas properties provide for additional consideration that is payable to Sellers based on increases in Nymex prices for oil and natural gas, without regard to changes in the Company’s oil and natural gas reserves (referred to as the “Price Increase Factor”). If Nymex thresholds of $90, $100, $110, $125 and $150 per barrel of oil are exceeded for periods of 61 days or more, incremental purchase consideration of $250,000, $250,000, $500,000, $500,000 and $2,000,000, respectively, will be payable to Sellers. Similarly, if Nymex thresholds of $5.00, $6.00, $7.50, $10.00 and $12.00 per MMbtu of natural gas are exceeded for periods of 61 days or more, incremental purchase consideration of $50,000, $50,000, $150,000, $250,000 and $250,000, respectively, will be payable to Sellers.

The maximum increase in purchase price for the Kansas and Colorado properties is limited to $5 million.

(b)

F-36

The maximum increase in purchase price (including Sellers retained interest of 70% for the Wyoming properties discussed in the preceding paragraph) for all properties in all states shown in the table above is limited to $25 million. Due to the sale of the Separate Interests discussed below, accrual of $250,000 due to a sustained increase in oil prices over $90 per barrel recorded during the fourth quarter of 2011, and the sale of a second property in February 2012, the maximum future consideration has been reduced by approximately $5.0 million to $20.0 million.

(c)

(d)

Prior to the complete payment for the Properties and formal closing on September 29, 2011, the Separate Interests were sold on August 23, 2011. The Company acquired the contractual rights associated with the Separate Interests on July 29, 2011, and the Company’s share of the net proceeds of $5,101,000 was received on August 23, 2011; the result was the recognition of a gain in the third quarter of 2011 of approximately $2,480,000. The Company applied the $5,101,000 of net proceeds to the payments due under the PSA.

2.	BASIS OF PRESENTATION :

The accompanying statements of operating revenues and direct operating expenses (the “Statements”) of the working interests in Oil and Gas Properties (“Properties”) acquired by the Company were prepared by the Sellers based on carved out financial information and data from the Properties’ historical accounting records. The Statements exclude the operating revenues and direct operating expenses of the Separate Interests described in Note 1. Historical financial statements prepared in accordance with generally accepted accounting principles have never been prepared for the Properties. The oil and gas wells that comprise the Properties were owned by between five and seventeen different owners and in most cases the original drilling and development activities took place up to thirty years prior to the Company’s acquisition.

Because the Properties are not separate legal entities, the accompanying Statements vary from a complete income statement in accordance with accounting principles generally accepted in the United States of America in that they do not reflect certain expenses that were incurred in connection with the ownership and operation of the Properties including, but not limited to, general and administrative expenses, interest expense, and other expenses. These costs were not separately allocated to the Properties in the accounting records of Sellers. In addition, these allocations, if made using historical general and administrative structures and tax burdens, may not produce allocations that would be indicative of the historical performance of the Properties had they been the Company’s properties due to the differing size, structure, operations and accounting policies of the Sellers and the Company.

F-37

The accompanying Statements also do not include provisions for depreciation, depletion, amortization and accretion, as such amounts would not be indicative of the costs which the Company will incur upon the allocation of the purchase price paid for the Properties. Furthermore, no balance sheet has been presented for the Properties, because not all of the historical cost and related working capital balances are segregated or easily obtainable, nor has information about the Properties operating, investing and financing cash flows been provided for similar reasons. Accordingly, the accompanying Statements are presented in lieu of the financial statements required under Rule 8-04 of Securities and Exchange Commission Regulation S-X.

3.	USE OF ESTIMATES IN PREPARATION OF FINANCIAL STATEMENTS:

The preparation of the Statements of Operating Revenues and Direct Operating Expenses of the Properties acquired by the Company in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of operating revenues and direct operating expenses during the respective reporting periods. Actual results may differ from the estimates and assumptions used in the preparation of the Statements of Operating Revenues and Direct Operating Expenses of the Properties acquired by the Company.

4.	CRITICAL ACCOUNTING POLICIES:

The Sellers record revenue from the sale of crude oil and natural gas in the month that delivery to the purchaser occurs and title has transferred. The impact of gas imbalances is not material.

Direct Operating Expenses include overhead charges, contract pumper services, salt water disposal, utilities, repairs, maintenance, and other direct costs. All Direct Operating Expenses, including the cost of workovers and repairs to well equipment, are charged to expense in the period incurred. For the years ended December 31, 2009 and 2010, the Sellers did not drill any wells on the properties acquired by the Company and, accordingly, all costs incurred to operate the wells have been included in lease operating expense.

5.	COMMITMENTS AND CONTINGENCIES:

Pursuant to the terms of the purchase and sale agreement, there are no known claims, litigation or disputes pending as of the effective date of the PSA, or any matters arising in connection with indemnification, and the parties to the agreement are not aware of any legal, environmental or other commitments or contingencies that would have a material adverse effect on the Operating Revenues and Direct Operating Expenses of the Properties acquired by the Company.

6.	SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (Unaudited):

The reserve information presented below is based on estimates of net proved reserves of the Properties as of December 31, 2009 and 2010 that were prepared by the Company’s independent petroleum engineering firm, in accordance with guidelines established by the SEC. This reserve information excludes the Separate Interests described in Note 1(d).

F-38

can be expected to be recovered through existing wells with existing equipment and operating methods. Estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors. All of the Properties’ proved reserves are located in the continental United States.

The following table sets forth information for the years ended December 31, 2009 and 2010 with respect to changes in the Properties’ proved developed and proved undeveloped reserves:


	Crude Oil (Bbl)			Natural Gas (Mcf)
Proved Reserves, December 31, 2008		310,267			678,564
Production during 2009		(23,995	)		(174,724	)

Proved Reserves, December 31, 2009		286,272			503,840
Revisions of previous estimates		119,176			274,864
Production during 2010		(23,572	)		(148,864	)

Proved Reserves, December 31, 2010		381,876			629,840

Proved developed reserves as of:
December 31, 2009		211,223			363,997

December 31, 2010		304,631			500,011

Proved undeveloped reserves as of:
December 31, 2009		75,049			139,843

December 31, 2010		77,245			129,829

As of December 31, 2009, future cash inflows were computed by applying the 12 month arithmetic average of the first of month price for January through December 31, 2009, which resulted in benchmark prices of $61.18 per barrel for crude oil and $3.87 per MMbtu for natural gas. Prices were further adjusted for transportation, quality and basis differentials, which resulted in an average price used as of December 31, 2009 of $50.60 per barrel of oil and $3.67 per Mcf for natural gas.

As of December 31, 2010, future cash inflows were computed by applying the 12 month arithmetic average of the first of month price for January through December 31, 2010, which resulted in benchmark prices of $79.43 per barrel for crude oil and $4.38 per MMbtu for natural gas. Prices were further adjusted for transportation, quality and basis differentials, which resulted in an average price used as of December 31, 2010 of $69.54 per barrel of oil and $4.12 per Mcf for natural gas.

F-39

A 10% annual discount rate was used to reflect the timing of the future net cash flows relating to proved oil and gas reserves.

Standardized Measure

The following table presents the standardized measure of discounted future net cash flows as of December 31, 2009 and 2010 related to proved oil and gas reserves for the oil and gas working interests acquired by the Company on July 29, 2011 (excluding the Separate Interests described in Note 1):


	2009			2010
Future cash inflows	$	16,331,439		$	29,151,354
Future production costs		(8,477,510	)		(13,800,670	)
Future development costs		(964,486	)		(964,486	)
Future income taxes		—			(2,162,972	)

Future net cash flows		6,889,443			12,223,226
10 percent annual discount		(3,116,967	)		(6,027,697	)

Standardized measure of discounted future net cash flows	$	3,772,476		$	6,195,529

The present value (at a 10% annual discount) of future net cash flows from proved reserves is not necessarily the same as the current market value of such oil and gas reserves. The estimated discounted future net cash flows from proved reserves is based on average prices realized in the preceding year and on costs in effect at the end of the year for such properties. However, actual future net cash flows from these oil and gas properties will also be affected by factors such as actual prices received for oil and gas, the amount and timing of actual production, supply of and demand for oil and gas and changes in governmental regulations or taxation.

The timing of both the production of oil and gas and the incurrence of expenses in connection with the development and production of oil and gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% annual discount factor used to calculate discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the properties, or the oil and gas industry in general.

F-40

Changes in Standardized Measure

A summary of changes in the standardized measure of discounted future net cash flows for the oil and gas working interests acquired by the Company on July 29, 2011, is as follows for the years ended December 31, 2009 and 2010:


	2009			2010
Standardized measure of discounted future net cash flows, beginning of year	$	4,237,566		$	3,772,476
Sales of oil and gas, net of production costs and taxes		(465,090	)		(746,856	)
Net changes in oil and gas prices and production costs		—			1,988,196
Changes in development costs		—			(100,618	)
Revisions in previous quantity estimates and other		—			2,001,471
Net changes in income taxes		—			(1,096,388	)
Accretion of discount		—			377,248

Standardized measure of discounted future net cash flows, end of year	$	3,772,476		$	6,195,529

Estimates of net proved reserves as of December 31, 2008 in accordance with SEC guidelines were not prepared. Accordingly, the changes in the standardized measure for 2009 do not include revisions in prior estimates, net changes in prices and production costs, accretion of discount or timing and other differences. No acquisition, drilling or other development activities occurring on the Properties during 2009 and 2010 and, accordingly, no amounts are shown for these activities in computing the changes in the standardized measure for 2009 and 2010.

F-41

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

UNAUDITED PRO FORMA CONSOLIDATED BALANCE SHEET

June 30, 2011


	Arête Historical			Pro Forma Adjustments								Arête Pro Forma
	Arête Historical			Acquisition				Sale/ Financing				Arête Pro Forma
ASSETS
Current Assets:
Cash and equivalents	$	21,457		$	—			$	24,418		*(e)*	$	45,875
Oil and gas sales receivable		—			1,229,830		*(c)*						1,229,830
Prepaid expenses and other		459,822											459,822

Total Current Assets		481,279											1,735,527

Property and Equipment:
Oil and gas properties, at cost, successful efforts method:					(189,937	)	*(c)*
Proved properties		—			7,830,265		*(b)*						8,540,328
					900,000		*(a)*
Unevaluated properties		—			287,728		*(b)*						287,728
Gas gathering pipeline and related assets		461,867											461,867

Total property and equipment		461,867											9,289,923
Less acc. depr., depletion & amortization		(206,241	)										(206,241	)

Net Property and Equipment		255,626											9,083,682

Separate Interests		—			2,621,113		*(b)*		(2,621,113	)	*(d)*		—

Deposit for acquistion of oil and gas properties		500,000			(500,000	)	*(a)*		—				—

TOTAL ASSETS	$	1,236,905		$	12,178,999			$	(2,596,695	)		$	10,819,209

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable	$	598,550		$	—			$	—			$	598,550
Accrued expenses		217,805			1,039,893		*(c)*						1,257,698
Note Payable for acquisition of properties		—			10,100,000		*(b)*		(5,101,047	)	*(d)*		—
									(4,998,953	)	*(e)*
Notes payable		355,219			400,000		*(a)*						755,219

Total Current Liabilities		1,171,574											2,611,467
Asset Retirement Obligations		—			639,106		*(b)*						639,106

Total Liabilities		1,171,574											3,250,573

Stockholders’ Equity:
Convertible Class A preferred stock:
Series 1; authorized 30,000 shares, issued and outstanding 522.5 shares after pro forma adjustments		—							5,023,371		*(e)*		5,023,371
Common stock, issued and outstanding 7,664,476 shares		16,804,154											16,804,154
Accumulated deficit		(16,738,823	)						2,479,934		*(d)*		(14,258,889	)

Total Stockholders’ Equity		65,331			—				—				7,568,636

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	1,236,905		$	12,178,999			$	(2,596,695	)		$	10,819,209

The Accompanying Notes are an Integral Part of These Pro Forma Financial Statements.

F-42

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS

Year Ended December 31, 2010


	Arête Historical			Pro Forma Adjustments				Arête Pro Forma
Revenues:
Oil and natural gas sales	$	—		$	2,086,939		*(f)*	$	2,086,939
Gas gathering income		167,625			—				167,625

Total revenues		167,625			2,086,939				2,254,564

Operating Expenses:
Gas gathering costs		327,591			(104,606	)	*(i)*		222,985
Lease operating expenses		—			1,172,340		*(f)*		1,172,340
Production taxes		—			167,742		*(f)*		167,742
Depreciation, depletion, and amortization		44,229			481,092		*(g)*		525,321
General and administrative		723,109			180,000		*(h)*		903,109

Total operating expenses		1,094,929			1,896,568				2,991,497

Operating income (loss)		(927,304	)		190,371				(736,933	)
Other income (expense):
Extinguishment of debt		121,870			—				121,870
Interest income		13			—				13
Interest expense		(47,191	)		(1,050,000	)	*(j)*		(1,097,191	)

Total other income (expense)		74,692			(1,050,000	)			(975,308	)

Net income (loss)	$	(852,612	)	$	(859,629	)		$	(1,712,241	)

Earnings (Loss) Per Share Applicable to Common Stockholders:
Basic	$	(0.17	)					$	(0.35	)

Diluted	$	(0.17	)					$	(0.35	)

Weighted Average Number of Common Shares Outstanding:
Basic		4,950,000							4,950,000

Diluted		4,950,000							4,950,000

The Accompanying Notes are an Integral Part of These Pro Forma Financial Statements.

F-43

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS

Six Months Ended June 30, 2011


	Arête Historical			Pro Forma Adjustments				Arête Pro Forma
Revenues:
Oil and natural gas sales	$	—		$	1,497,315		*(f)*	$	1,497,315
Gas gathering income		45,639			—				45,639

Total revenues		45,639			1,497,315				1,542,954

Operating Expenses:
Gas gathering costs		111,373			(30,815	)	*(i)*		80,558
Lease operating expenses		—			560,649		*(f)*		560,649
Production taxes		—			121,183		*(f)*		121,183
Depreciation, depletion, and amortization		22,110			293,126		*(g)*		315,236
Acquisition expenses		457,500			—				457,500
General and administrative		714,566			90,000		*(h)*		804,566

Total operating expenses		1,305,549			1,034,143				2,339,692

Operating income (loss)		(1,259,910	)		463,172				(796,738	)
Other income (expense):
Interest income		279			—				279
Interest expense		(34,442	)		(525,000	)			(559,442	)

Total other income (expense)		(34,163	)		(525,000	)			(559,163	)

Net income (loss)	$	(1,294,073	)	$	(61,828	)		$	(1,355,901	)

Earnings (Loss) Per Share Applicable to Common Stockholders:
Basic	$	(0.22	)					$	(0.23	)

Diluted	$	(0.22	)					$	(0.23	)

Weighted Average Number of Common Shares Outstanding:
Basic		5,995,000							5,995,000

Diluted		5,995,000							5,995,000

The Accompanying Notes are an Integral Part of These Pro Forma Financial Statements.

F-44

ARÊTE INDUSTRIES, INC.

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

1.	BASIS OF PRESENTATION

Arête Industries, Inc. (the “Company”) entered into an Amended and Restated Purchase and Sale Agreement (“PSA”) on July 29, 2011. As set forth in the PSA and its related exhibits, the principal assets acquired by the Company consisted of (i) working interests in oil and gas properties located in Wyoming, Colorado, Kansas and Montana (referred to as the “Properties”), and (ii) vested contractual rights in the net proceeds from the future sale of certain properties located in Wyoming (referred to as the “Separate Interests”). With respect to the Separate Interests, a formal closing and transfer of title was not required, and did not occur, in order for the Company to realize its vested contractual rights to the proceeds related to the sale of the Separate Interests. The Company acquired the contractual rights associated with the Separate Interests on July 29, 2011, and the Company’s share of the net proceeds from the sale of the Separate Interests of $5,101,000 was received on August 23, 2011, which resulted in recognition of a gain of approximately $2,480,000. An unaudited pro forma consolidated balance sheet has been prepared to reflect (i) the purchase of the Properties, (ii) the acquisition of the vested contractual rights to the Separate Interests, (iii) the sale of the Separate Interests, and (iv) the issuance of preferred stock used to finance the acquisition of the Properties.

The unaudited pro forma consolidated balance sheet presents the acquisition of the Properties, and the acquisition and sale of the Separate Interests, as if those transactions occurred on June 30, 2011. The pro forma unaudited consolidated statements of operations present the acquisition of the Properties as if they occurred at the beginning of the periods covered by the unaudited pro forma consolidated statements of operations. The impact of the acquisition and sale of the Special Interests is reflected in the unaudited pro forma consolidated balance sheet but is not reflected in the unaudited pro forma consolidated statements of operations.

These unaudited pro forma consolidated financial statements are not necessarily indicative of the financial position or results of operations that would have occurred had the acquisition been effected on the assumed dates. Additionally, future results may vary significantly from the results reflected in the unaudited pro forma consolidated statements of operations due to normal production declines, changes in prices, future transactions, and other factors. The Company currently has provided a full valuation allowance against net deferred tax assets. The Company believes that the acquisition would not result in an immediate change in the Company’s assessment regarding the valuation allowance. As such, no income tax adjustments from the acquisition have been reflected in the unaudited pro forma consolidated financial information.

For financial accounting purposes, the acquisition of the working interests and the Separate Interests are not considered a business combination under SFAS No. 141R, Business Combinations , as codified in FASB ASC Topic 805, Business Combinations . This determination was arrived at by considering key processes that were not acquired as part of the acquisition. No employees were acquired as part of the acquisition. Specifically, after the acquisition the Company will require highly specialized employees and/or consulting resources to manage and replicate key elements related to the Properties that were previously provided by the Sellers. Key processes that were not acquired include the geological, geophysical and engineering expertise directly related to these specific properties that will be needed to fully exploit the horizontal and recompletion potential for the Properties.

F-45

These unaudited pro forma consolidated financial statements should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2011, the Statements of Operating Revenues and Direct Operating Expenses for the years ended December 31, 2009 and 2010 and for the six months ended June 30, 2010 (unaudited) and 2011 (unaudited).

The acquisition agreement also provides for contingent consideration based on future increases in oil and gas prices and the results of future drilling activities. Contingent consideration that may be payable in the future will generally be recognized when it is probable and reasonably estimable. As December 31, 2011, $250,000 of additional consideration became payable due to the $90 oil price threshold and this amount is not reflected in the pro forma financial information.


Base Purchase Price:
Consideration Paid for Acquisition:
Cash	$	900,000
Note payable to seller		10,100,000

Total base purchase price paid for acquisition	$	11,000,000

Allocation of Purchase Price:
Separate Interests	$	2,621,113
Proved oil and gas properties		8,540,328
Unproved oil and gas properties		287,728

Total fair value of oil and gas properties acquired		11,449,169
Working capital acquired		189,937
Asset retirement obligations assumed		(639,106	)

Fair value of net assets acquired	$	11,000,000

Working capital acquired was estimated as follows:
Oil & gas sales receivable	$	1,229,830
Non-interest bearing payable to seller		(576,791	)
Accrued lease operating expenses		(463,102	)

Total working capital acquired	$	189,937

2.	PRO FORMA ADJUSTMENTS TO THE CONSOLIDATED BALANCE SHEET

Presented below is an explanation of the pro forma adjustments to the accompanying unaudited pro forma consolidated balance sheet:

(a)

Reflects borrowings in July 2011 used to fund an additional deposit of $400,000 under the PSA. This deposit plus the original deposit of $500,000 were applied to the purchase price of the properties at closing.

F-46

(b)

Under the PSA, the sellers provided interim financing of $10,100,000 and the Company assumed the asset retirement obligations related to the Properties, resulting in a preliminary purchase allocation of $2,621,113 to the Separate Interests, $287,728 to unevaluated properties and the remainder of $8,540,328 was assigned to the Properties.

(c)

The effective date of the acquisition was April 1, 2011. The net proceeds from oil and gas sales of $1,229,830, less accrued lease operating expenses of $463,102 incurred prior to the July 29, 2011 acquisition date are reflected as a net reduction of $766,728 to the purchase price allocation ($628,260 for the Properties and $138,468 for the Separate Interests). The purchase consideration also included a non-interest bearing payable of $576,791 and the pro forma adjustment for this amount is also included under accrued expenses.

(d)

On August 23, 2011, the Separate Interests were sold and the Company’s share of the net proceeds of $5,101,047 was used to retire a portion of the note payable to Sellers. After deducting the portion of the purchase price allocated to the Special Interests of $2,621,113, the Company recognized a gain of $2,479,934 which is reflected as a reduction in the accumulated deficit in the pro forma balance sheet.

(e)

On September 29, 2011, the Company issued in a private placement 522.5 shares of its Series A1 Preferred Stock for gross proceeds of $5,225,000. After deducting offering costs of $201,629 the Company received net proceeds of $5,023,371 which were primarily used to retire the remaining balance of the seller note payable.

3.	PRO FORMA ADJUSTMENTS TO THE CONSOLIDATED STATEMENTS OF OPERATIONS

Presented below is an explanation of the pro forma adjustments to the accompanying unaudited pro forma consolidated statements of operations:

(f)

The actual oil and gas revenues and direct operating expenses for the acquired working interest properties are included as a pro forma adjustment as if the acquisition occurred at the beginning of the period.

(g)

Depreciation, depletion, amortization and accretion are based on historical production and estimated reserves for the acquired working interest properties. The cost assigned to each field is based upon the preliminary purchase price allocation.

(h)

The cost of administrative support services under a post-acquisition contract operating agreement of approximately $15,000 per month are shown as an increase in general and administrative expenses. This agreement was entered into with the former owners in connection with the acquisition agreement.

(i)

Gas gathering production costs incurred with the former owners of the acquired properties are eliminated since the Company purchased the coal bed methane property and will not incur these costs after the acquisition.

(j)

Adjustment to record interest expense on $10.1 million of seller financing and an additional $400,000 borrowed to finance a deposit for the acquisition. Interest is provided based on the 10% per annum rate in the Seller note payable.

F-47

1,583,333 Shares of

Common Stock

ARÊTE INDUSTRIES, INC.

PROSPECTUS

October 31, 2012

You should rely only on the information contained in this document or that we have referred you to. We have not authorized anyone to provide you with information that is different. This prospectus is not an offer to sell common stock and is not soliciting an offer to buy common stock in any state where the offer or sale is not permitted.

Grafico Azioni Arete Industries (CE) (USOTC:ARET)
Storico
Da Dic 2024 a Gen 2025

Clicca qui per i Grafici di Arete Industries (CE)

Grafico Azioni Arete Industries (CE) (USOTC:ARET)
Storico
Da Gen 2024 a Gen 2025

ARET Arete Industries Inc (CE)

Notizie Arete Industries, Inc. (QB) - ARET

La tua Cronologia

Più Attivi

Toplist

ARET Arete Industries Inc (CE)

Notizie Arete Industries, Inc. (QB) - ARET

La tua Cronologia