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0001193125-12-164739.txt : 20120416 0001193125-12-164739.hdr.sgml : 20120416 20120416172001 ACCESSION NUMBER: 0001193125-12-164739 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 9 CONFORMED PERIOD OF REPORT: 20111231 FILED AS OF DATE: 20120416 DATE AS OF CHANGE: 20120416 FILER: COMPANY DATA: COMPANY CONFORMED NAME: ARETE INDUSTRIES INC CENTRAL INDEX KEY: 0000820901 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 841063149 STATE OF INCORPORATION: CO FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 033-16820-D FILM NUMBER: 12761989 BUSINESS ADDRESS: STREET 1: 7260 OSCEOLA STREET CITY: WESTMINSTER STATE: CO ZIP: 80030 BUSINESS PHONE: 303-652-3113 MAIL ADDRESS: STREET 1: 7260 OSCEOLA STREET CITY: WESTMINSTER STATE: CO ZIP: 80030 FORMER COMPANY: FORMER CONFORMED NAME: TRAVIS INDUSTRIES INC DATE OF NAME CHANGE: 19930614 FORMER COMPANY: FORMER CONFORMED NAME: TRAVIS INVESTMENTS INC DATE OF NAME CHANGE: 19890427 10-K 1 d313322d10k.htm FORM 10-K Form 10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2011

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 33-16820-D

Arête Industries, Inc.

(Exact Name Of Registrant As Specified In Its Charter)


Colorado		84-1508638
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)

P. O. Box 141 Westminster CO		80036
(Address of Principal Executive Offices)		(ZIP Code)

Registrant’s Telephone Number, Including Area Code: (303) 427-8688

Securities registered under Section 12(b) of the Exchange Act: None

Securities registered under Section 12(g) of the Exchange Act: None

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

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

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

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

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

On March 31, 2012 the aggregate market value of the 5,954,448 common stock held by non-affiliates of the Registrant was approximately $8,336,227.

On March 31, 2012 the Registrant had 7,764,476 shares of common stock outstanding.


	PART I

ITEM1.	Description of Business	3

ITEM 1A.	Risk Factors	10

ITEM 1B	Unresolved Staff Comments	16

ITEM 2.	Description of Properties	16

ITEM 3.	Legal Proceedings	17

ITEM 4.	Submission of Matters to a Vote of Security Holders	17

	PART II

ITEM 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	18

ITEM 6.	Selected Financial Data	20

ITEM 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20

ITEM 8.	Financial Statements and Supplementary Data.

ITEM 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	54

ITEM 9-A(T)	Controls and Procedures	54

ITEM 9-B	Other Information	55

	PART III

ITEM 10.	Directors, Executive Officers and Corporate Governance.	55

ITEM 11.	Executive Compensation	59

ITEM 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	61

ITEM 13.	Certain Relationships and Related Transactions, and Director Independence	62

ITEM 14.	Principal Accountant Fees and Services	63

	PART IV

ITEM 15.	Exhibits and Financial Statement schedules	65

Cautionary Note Regarding Forward-Looking Statements

This report contains certain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act of 1934, as amended, that are based on management’s exercise of business judgment as well as assumptions made by, and information currently available to, management. When used in this document, the words “may”, “will”, “anticipate”, “believe”, “estimate”, “expect”, “intend”, and words of similar import, are intended to identify any forward-looking statements. You should not place undue reliance on these forward-looking statements. These statements reflect our current view of future events and are subject to certain risks and uncertainties as noted below. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, our actual results could differ materially from those anticipated in these forward-looking statements. Although we believe that our expectations are based on reasonable assumptions, we can give no assurance that our expectations will materialize.

Unless the context otherwise requires, references in this Annual Report to “The Company,” “Arete,” “we” “us,” “our” or “ours” refer to Arête Industries, Inc.

PART 1

ITEM 1. DESCRIPTION OF BUSINESS

Company Overview

Arête Industries, Inc. was 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.areteindustries.com.

We are a publicly traded company trading on the OTC Markets OTC-QB under the symbol: ARET. The Company has been publicly traded since 1987, and has over 4,000 shareholders.

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act of 1934 will be available through our Internet website as soon as reasonably practical after we electronically file such material with, or furnish it to, the Securities and Exchange Commission.

Mr. Donald W. Prosser continued his responsibilities as Chairman and Chief Executive Officer. Mr. Charles Gamber is the Corporate Secretary, John R. Herzog is the acting CFO, and Mr. Charles B. Davis serves as Chief Operating Officer who joined the Company because of his oil & gas background and great experience in the business. We are in the process of expanding the number of board members to at least seven.

In September 2006, the Company acquired a gas gathering system (pipeline and compressor station related assets) located 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 currently transporting approximately 900,000 Mcf (thousand cubic feet) of coal bed methane per day and had been cash flowing from its operations until the June 2011 when we did not sell natural gas due to the low prices being paid. This system has a current throughput capacity of approximately 4 million cubic feet (“MMcf”) of gas per day. Gathering fees are subject to contracts which are life of lease or 10-year contracts expiring in 2012.

In May 2011 we entered into a Purchase and Sale Agreement for the purchase of certain oil and gas operating properties in Colorado, Kansas, Wyoming, and Montana. The purchase price for the acquisition was $11,000,000. The purchase is part of our strategy to enter the oil and natural gas exploration and production business. Potential

additional purchase price payments are due under the following circumstances. If the Company increases is 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 defined percentage 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 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. Part of our strategy is to monitor the current production, seek to develop the property with infield drilling, explore sales and purchases of additional leases and operating wells with upside potential. We are currently evaluating several opportunities for drilling in Kansas and Colorado. We have had preliminary discussions on three properties for sale, joint venture, or farm-out in Wyoming. However, we need to augment our current financial potential to establish a plan for the development in Wyoming.

As part of the purchase we had an agreement 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 us. In fact, some of these properties were sold and we recognized a gain on the sale of these assets of $2,479,934 in the year ended December 31, 2011.

The following table provides information regarding our oil and natural gas producing assets and operations located in our core areas of operations.


	Proved Reserves at 2011 Year-End											2011 Average Monthly Production (BBLe) *(e)*
	Quantity (BBLe) *(a)*		Pre-Tax PV 10% *(b)*		% Oil *(c)*			Productive Wells During 2011
State	Quantity (BBLe) *(a)*		Pre-Tax PV 10% *(b)*		% Oil *(c)*			Gross		Net (d)
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		53

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

(a)

BBLe 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 BBLe using the ratio of six Mcf of natural gas to one barrel of oil.

(d)

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 July 29, 2011.

(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 July 29, 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 under SEC regulations 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, the use of a pre-tax measure provides greater comparability of assets when evaluating companies. We believe that most 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

The following table reconciles the Standardized Measure to PV 10%:


	Standardized Measure			Reserve Study
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	)(a)		(9,959,485	)

Standardized measure of discounted future net cash flows	$	8,342,000		$	10,865,445

(a) Income Tax Reconciliation
Income effect on PV10%	$	(2,163,756	)
10 percent annual discount		9,959,485

Income tax 10 percent annual discount	$	7,795,729	(a)

Business Strategy

Our business strategy is three fold in approach. 1) We plan to and have acquired oil and natural gas operating properties that will provide for the operation of the Company. 2) Acquire leases that have development possibility either for us to drill and or with other companies on a joint venture or farm-out basis to provide controlled growth. 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. 3) 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 will compete with numerous other companies engaged in the exploration and production of oil and gas. Some of these companies have substantially greater resources than we have. Not only do they explore for and produce oil and natural gas, but also many carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. The operations of other companies may be able to pay more for exploratory prospects and productive oil and natural gas properties. They may also have more resources to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit.

Our larger or integrated competitors may have the resources to be better able to absorb the burden of current and future federal, state, and local laws and regulations more easily than we can, which would adversely affect 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 producing oil and natural gas properties and bidding for exploratory prospects because we have fewer financial and human resources than other companies in our industry. Should a larger and better financed company decide to directly compete with us, and be successful in its efforts, our business could be adversely affected.

Industry Overview

The oil and gas industry has undergone a renaissance in both the balance of supply and demand and in technological advances. In recent years, large petroleum companies have migrated their spending toward exploration and production projects overseas and offshore, particularly deep water, as well as into downstream ventures. Such companies have consolidated their United States onshore investments into core geographic areas. The majors and large independents follow the rule that “90% of our revenue comes from 10% of our properties.”

The majors and large independents are, in varying degrees, burdened with high infrastructure overhead that when allocated to these properties make the properties unattractive for additional investment. The infrastructure for large companies includes services for human resources, information technology, accounting, land and division orders, and legal departments. Divesting of these non-core properties was made to independents and start-up companies. Independents also acquired large areas of leases particularly in the Haynesville, Marcelius, Bakken and now the Eagleford shale. This required the companies to drill quickly or lose the leases. That focus may have left some other on-going fields to be without re-investment. We believe this gradual migration of spending has possibly left onshore opportunities for nimble and experienced, lower cost oil and gas producers.

Marketing and Customers

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

Our oil production is expected to be sold at prices tied to the spot oil markets. Our natural gas production is expected to be sold under short-term contracts and priced based on first of the month index prices or on daily spot market prices. We will rely on our operating partners 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. 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.

Governmental Regulations

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

Regulation of Oil and Natural Gas Production

Our oil and natural gas exploration, production and related operations, when developed, will be subject to extensive rules and regulations promulgated by federal, state, tribal 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 will most likely increase our cost of doing business and may affect our profitability. Although we believe we are currently in substantial compliance with all applicable laws and regulations, because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws. Significant expenditures may be required to comply with governmental laws and regulations and may have a material adverse effect on our financial condition and results of operations.

Regulation of 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 legislation and 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. A number of agencies including but not limited to the EPA, the BLM, the TCEQ, the LDNR, the NDIC, the OCC, the WOGCC, the MBOGC and similar commissions within these states and of other

states in which we do business have adopted regulatory guidance in consideration of the operational limitations on these types of facilities and their potential to emit pollutants. 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 employees and no part time employees. 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 five 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.

ITEM 1A. RISK FACTORS

The following risks with respect to our proposed business and financial condition should be carefully considered. These risks and uncertainties are not the only ones facing us. Other risks and uncertainties that have not been predicted or assessed by us may also adversely affect us. Some of the information in this report 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

The risks and uncertainties described below are not the only risks facing us. Additional risks not presently known to us or which we consider immaterial based on information currently available to us may also materially adversely affect us. If any of the following risks or uncertainties actually occurs, our business, financial condition and results of operations could be adversely affected.

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

Our operations commenced with our acquisition of certain assets of PRB Gas Transportation, Inc. as of September 2006. As a result, we have little historical financial and operating information available to help you evaluate our performance or an investment in our common stock.

To fund our future growth we will require additional capital, 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 may 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 could be adversely affected.

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

As we expand and require capital, we intend to enter into credit agreements with financial institutions to fund a portion of the 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 for our future growth.

We depend on our chief executive officer for critical management decisions and industry contacts.

We are heavily dependent upon the efforts of our Chief Executive Officer, Donald W. Prosser. We do not have an employment agreement with him nor do we have any key man insurance on his life. The loss of Mr. Prosser’s services would likely have a material adverse impact on our business.

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. As we continue to grow our asset base and the scope of our operations, our future profitability will depend on our ability to attract and retain qualified personnel, particularly individuals with a strong background in geology, geophysics, engineering and operations.

A significant decrease in the supply of natural gas from our gas gathering customers could materially affect our results of operations and financial condition.

Investments by our gas gathering customers in the maintenance of existing wells and the further development of their reserves will affect their production rates and the volume of gas we gather. Drilling activity generally decreases as gas prices decrease. We have no control over our customers’ level of drilling activity, the amount of reserves underlying their wells and the rate at which their production from a well will decline. Drilling activity of our customers is affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, geological considerations, governmental regulation and the availability and cost of capital.

Any material nonpayment or nonperformance by our key customers could materially affect our results of operations and financial condition.

Some of our customers may be highly leveraged and subject to their own operating and regulatory risks.

Our operations are subject to operational hazards and unforeseen interruptions for which we may be inadequately insured.

Our operations, both gathering and processing and exploration and production, are subject to operational hazards and unforeseen interruptions such as natural disasters, adverse weather, accidents, fires, explosions, hazardous materials releases, mechanical failures and other events beyond our control. These events might result in a loss of equipment or life, injury or extensive property damage, as well as an interruption in our operations. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our results of operations and financial condition.

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

The search for commercial quantities of oil and natural gas as a business is extremely 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.

Our business depends on the level of activity in the oil and gas industry, which is significantly affected by volatile energy prices.

Our business depends on the level of activity in oil and gas exploration, development and production in markets worldwide. Oil and gas prices, market expectations of potential changes in these prices and a variety of political and economic and weather-related factors significantly affect this level of activity. Oil and gas prices are extremely volatile and are affected by numerous factors, including:

•

Worldwide demand for oil and gas;

•

The ability of the Organization of Petroleum Exporting Countries, commonly called “OPEC,” to set and maintain production levels and pricing;

•

The level of production in non-OPEC countries;

•

The policies of the various governments regarding exploration and development of their oil and gas reserves;

•

Local weather;

•

Fluctuating pipeline takeaway capacity;

•

Advances in exploration and development technology;

•

The political environment surrounding the production of oil and gas;

•

Level of consumer product demand; and

•

The price and availability of alternative fuels.

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 properties quarterly based on prices in effect as of the end of each quarter or as of the time of reporting our results. 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 capital in the equity markets.

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 throughout the world, 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 SEC regulation and reporting obligations. 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, 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.

Risks Related to Our Common Stock

We are not obligated to pay cash dividends on the Series A1 Preferred Stock and you should not consider the stock to be an investment for income.

The declaration and payment of any cash dividends on the Series A1 Preferred Stock will be solely at the discretion of our Board of Directors. We cannot make assurances that we will pay dividends on the Series A1 Preferred Stock. The entitlement of dividends on the Series A1 Preferred Stock of 15% per annum only applies to the extent when and if declared by our Board of Directors. Thus, you should not consider an investment in the Series A1 Preferred Stock to be one that will generate dividend income to you.

There are restrictions on the transferability of our Series A1 Preferred Stock and Common Stock.

The shares of Series A1 Preferred Stock offered by this Offering Circular are subject to restrictions on transfer pursuant to applicable federal and state securities laws. Each investor agreed in the Subscription Agreement that a legend will be placed on the Series A1 Preferred Stock certificates and any common stock certificates acquired through the exercise of the conversion rights applicable to the stock purchased hereunder, stating that the securities have not been registered under the Securities Act or any state securities laws, setting forth or referring to the restrictions on transferability or sale of such securities and that transfer instructions will be given by us to restrict transfer of such securities. In addition, while we are providing registration rights relating to a subsequent public sale by investors herein of shares of our common stock which they may receive in connection with conversions of the Series A1 Preferred Stock, there can be no assurance that such common shares can be registered with the SEC in a timely manner.

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. Additional shares of common stock may be issued pursuant to the exercise of stock options issued under our incentive plans or a future offering of shares of common stock. The value of an investor’s investment in our Series A1 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, new products or product enhancements by us or our competitors 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 filing of this report, could have a material adverse effect on the market price of our shares.

Trading in shares of companies, such as ours, listed on the Pink Sheets in general and trading in shares of technology companies in particular have been subject to extreme price and volume fluctuations that have been unrelated or disproportionate to operating or other performance.

The common stock is considered a “penny stock”

The SEC has adopted regulations which generally define “penny stock” to be an equity security that has a market or exercise price of less than $5.00 per share, subject to specific exemptions. The market price of the common stock may drop below $5.00 per share and therefore may be designated as a “penny stock” according to SEC rules. This designation requires any broker or dealer selling these securities to disclose certain information concerning the transaction, obtain a written agreement from the purchaser and determine that the purchaser is reasonably suitable to purchase the securities. These rules may restrict the ability of brokers or dealers to sell the securities and may affect the ability of investors to sell their shares.

We Have not Paid Cash Dividends in the Past on our Common Stock and do not Expect to pay Cash Dividends in the Future. Any Return on Investment may be Limited to the Value of Our Stock.

We have never paid cash dividends on our Common Stock and do not anticipate paying cash dividends on our Common Stock in the foreseeable future. The payment of cash dividends on our Common Stock will depend on our earnings, financial condition and other business and economic factors affecting us at such time as our Board of Directors may consider relevant. If we do not pay cash dividends, our Common Stock may be less valuable because a return on an investor’s investment will only occur if our Common Stock price appreciates.

Concentration of share ownership among our existing executive officers, Directors and principal stockholders may prevent others from influencing significant corporate decisions.

At December 31, 2011, our executive officers, Directors and principal stockholders beneficially own approximately 23.313% of our outstanding common stock. As a result, these stockholders, acting together, will have the ability to exert substantial influence over all matters requiring approval by our stockholders, including the election and removal of Directors and any proposed merger, consolidation or sale of all or substantially all of our assets and other corporate transactions. This concentration of ownership could be disadvantageous to other stockholders with interests different from those of our officers, Directors and principal stockholders.

Access to Information

Our website address is www.areteindustries.com We make available, free of charge, on the “Filings” 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 Securities and Exchange Commission (“SEC”). We also make available through our

website other reports electronically filed with the SEC under the Securities Exchange Act of 1934, including our proxy statements and reports filed by officers and Directors under Section 16(a) of that Act. We do not intend for information contained in our website to be part of this Annual Report on Form 10-K.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None

ITEM 2. PROPERTIES

Oil and Natural Gas Properties

The following table lists the oil and natural gas properties we have by state and field;


	County	Productive Wells				Proved Reserves
Field	County	Gross		Net *(a)*		(BBLe) *(b)*
Wyoming:
Rex Lake	Albany		8.0		8.0		36,230
Buff	Campbell		8.0		8.0		43,296
Shippy	Campbell		1.0		1.0		64,370
Bobcat Creek	Converse		2.0		1.5		14,716
Other	Various		21.0		15.8		64,375
Kansas:
Big Bow	Stanton		2.0		0.6		62,952
Granger Creek	Clark		1.0		1.0		48,568
Walz	Trego		1.0		0.9		33,040
Other	Graham		1.0		0.9		15,026
Colorado:
Gemini	Weld		2.0		2.0		40,278
Smokey Creek	Cheyenne		1.0		0.7		33,852
Wild Horse	Weld		1.0		1.0		6,404
Other	Various		4.0		4.0		43,571
Montana:
Police Coulee	Toole		2.0		1.4		6,223

			55.0		46.8		512,901

(a)

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

(b)

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

Gas Gathering System

In September 2006, the company acquired a gas gathering system (Pipeline and compressor station related assets) located 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. This pipeline is currently shut-in and not generating revenue.

This system has a current throughput capacity of approximately 4 million cubic feet (“MMcf”) of gas per day. Gathering fees are subject to contracts which are life of lease or 10-year contracts expiring in 2012.

Description of Properties - Powder River Basin Geology

In December 1994, there were approximately 200 wells in the Powder River Basin producing coal-bed methane gas. Since 1994, over 15,000 gas wells have been drilled in this area and the State of Wyoming and the Bureau of Land Management (“BLM”) have the authority to grant over 15,000 additional drilling permits. Production in 1994 was 2.4 billion cubic feet, and production in 2003 was 3.46 billion cubic feet (Source: Wyoming Oil and Gas Conservation Commission). The average well-life of coal-bed methane well is estimated by the BLM to be eight to ten years.

Gas produced from Powder River Basin coals is almost 100% methane. The gas is generated during the coal forming process and is trapped in the coal beds by water. In order to produce the coal gas, the formation must first be dewatered. As the water is removed from the coal, the gas is desorbed from the coal. All of the coal-bed reservoirs are low pressure and require compression in order for the gas to be delivered to a pipeline transportation system.

Natural gas wells in the Powder River Basin area typically experience sharp declines in production volume in the first several years of production. Production then stabilizes and declines more ratably over a gas well’s average life of approximately eight to ten years. Other factors which influence the initial and long term productivity of the coal-bed methane wells are the depths of the coal fields, the initial gas saturation levels of the coal field and the well spacing.

Office Facilities

We currently lease office space, from a director, in Westminster, Colorado.

Storage Facilities

We currently rent a storage locker close to our office in Westminster, Colorado

ITEM 3. LEGAL PROCEEDINGS

None

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

(a)

The following table sets forth the range of high and low bid price information for our Common Stock for each fiscal quarter for the past two fiscal years as reported by the Pink OTC Markets Inc. and obtained from Yahoo Finance. High and low bid quotations which represent prices between dealers without adjustment for retail mark-ups, markdowns or commissions.

(b)


	HIGH BID		LOW BID
Year Ended December 31, 2011:
First Quarter	$	0.085	$	0.0105
Second Quarter		6.150		0.0430
Third Quarter		5.150		2.5000
Four Quarter		3.250		1.0600
Year Ended December 31, 2010:
First Quarter	$	0.0220	$	0.0060
Second Quarter		0.0165		0.0085
Third Quarter		0.0150		0.0080
Four Quarter		0.0230		0.0090

On April 10, 2011 the Company reversed it’s Common stock 100 to 1 and prices above are reflected before and after the reverse of the common shares at the actual price and trade volume.

Since our shares have been quoted in the over-the-counter market on the Pink Sheets, the prices for our shares have fluctuated widely. There may be many factors that explain these variations. We believe that such factors include (a) the demand or lack thereof for our Common Stock, (b) the number of shares of our Common Stock available for sale, and (c) changes in the performance of the stock market in general, among others.

In recent years, the stock market has experienced extreme price and volume fluctuations that have had a substantial effect on the market prices for many small and emerging growth companies such as our company, which may be unrelated to the operating performances of the specific companies. Some companies that have experienced volatility in the market price of their stock have been the targets of securities class action litigation. If we became the target of securities class action litigation, it could result in substantial costs and a diversion of management’s attention and resources and have an adverse effect on our ability to implement our business plan. In addition, holders of shares of our Common Stock could suffer substantial losses as a result of fluctuations and declines in the market price of our Common Stock.

Holders

As of December 31, 2011, the approximate number of holders of record of shares of our Common Stock, $.001 par value per share, our only class of trading securities, was believed by management to be as follows:


Title of Class	Number of Record Holders
Common Stock, $.001 par value		4,827

The number of record holders of our Common Stock was determined from the records of our transfer agent and does include numerous beneficial owners of our Common Stock whose shares are held in the names of various security brokers, dealers, and registered clearing agencies. The above number of holders record is an estimate but the exact number of these shareholders is unknown to us.

Dividends

The Company has not paid any dividends with respect to its common stock and it is not anticipated that the company will pay dividends in the foreseeable future. Accrued but undeclared on preferred stock of $196,000 at December 31, 2011 are reflected in the earnings per share calculated on March 30, 2012, the Company declared a dividend on its preferred stock for approximately $392,000.

Penny Stock Rules

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 market 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. The penny stock rules require a broker-dealer, prior to a transaction in a penny stock, to deliver a standardized risk disclosure document prepared by the SEC, that: (a) contains a description of the nature and level of risk in the market for penny stocks in both public offerings and secondary trading; (b) 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 of such duties or other requirements of the securities laws; (c) 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; (d) contains a toll-free telephone number for inquiries on disciplinary actions; (e) defines significant terms in the disclosure document or in the conduct of trading in penny stocks; and (f) 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, the customer with (a) bid and offer quotations for the penny stock; (b) the compensation of the broker-dealer and its salesperson in the transaction; (c) 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 (d) a monthly account statement 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 as to transactions involving penny stocks, and a signed and dated copy of a written suitability statement.

These disclosure requirements may have the effect of reducing the trading activity for our Common Stock. Therefore, stockholders may have difficulty selling our securities.

Our Transfer Agent

Computer Share Investor Services is the transfer agent for our Common Stock. They can be contacted at Computer Share, Inc., Registry Team, 250 Royall Street, Canton, MA 02021; phone: (303) 262-0378; facsimile: (303) 262-0700.

Recent Sales of Unregistered Securities

We had no sales of unregistered securities during the three month period ended December 31, 2011.

Repurchases of Equity Securities of the Issuer

None

ITEM 6. SELECTED FINANCIAL DATA

As a smaller reporting issuer (as defined by in Item 10(f)(1) of Regulation S-K), the Company is not required to report selected financial data specified in Item 301 of Regulation S-K.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Forward-looking information

Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read together with our audited financial statements and related notes included elsewhere in this Annual Report on Form 10-K. This Annual Report on Form 10-K, including the following discussion, contains trend analysis and other forward-looking statements within the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Any statements in this Annual Report on Form 10-K that are not statements of historical facts are forward-looking statements. These forward looking statements made herein are based on our current expectations, involve a number of risks and uncertainties and should not be considered as guarantees of future performance. The factors that could cause actual results to differ materially include without limitation:

•

Dependence on key management personnel;

•

Competitors with greater financial resources;

•

The ability of management to execute acquisition and expansion plans and motivate personnel in the execution of such plans;

•

Adverse publicity related to the company, or the industry;

•

An inability to arrange additional debt or equity financing;

•

The adoption of new, or changes in, accounting principles;

•

The costs inherent with complying with new statutes and regulations applicable to public reporting companies, such as the Sarbanes-Oxley Act of 2002;

•

The interruptions or cancellation of existing contracts;

•

Economic downturn;

•

Price of oil and natural gas.

Actual results may differ materially from those set forth in such forward-looking statements as a result of factors set forth elsewhere in this Annual Report on Form 10-K, including under “Risk Factors.” More information about factors that potentially could affect the Company’s financial results is included in our filings with the Securities and Exchange Commission. The Company is under no obligation and does not intend to update, revise or otherwise publicly release any revisions to these forward-looking statements to reflect events or circumstances after the date hereof or to reflect the occurrence of any unanticipated events.

General Overview

It is our desire to provide all parties who may read this MD&A an understanding of the Company’s past performance, its financial condition and its prospects of going forward in the future. Accordingly, we will discuss and provide our analysis of the following:

•

Overview of the business;

•

Critical accounting policies;

•

Results of operations;

•

Overview of business segments;

•

Liquidity, capital resources and outlook for 2012;

•

New accounting pronouncements.

We own and operate a natural gas gathering system (pipeline and compressor station related assets) in the Powder River Basin of Wyoming. We acquired this system in September 2006 and commenced operations shortly thereafter. The acquisition of the gas gathering system and working interests is intended to generate cash flow to enable us to service our debts and allow us to proceed with the proposed acquisition. We made an acquisition that included oil and natural gas properties in Montana, Wyoming, Colorado and Kansas. These properties include PUD’s and off-set opportunities with most of the leases. The plan also includes financing for the drilling of these opportunities, sale of some of the leases as a revenue source while keeping the overriding royalty interests, and development of the sites. In addition, we are in the process of reviewing several opportunities for the purchase of production and leases for future development.

Management Discussion

While we are very optimistic about our progress on this plan to benefit the shareholders of this company there are no assurances that we can resolve all of our capital needs, and although have revenue from operations, our ability to completely execute our plans will still be depend on our ability to raise additional capital. We have not received a commitment to finance the drilling. We have commitment requests from outside parties, banks, as well as related parties are more likely than not to happen. We currently have created cash flow that is sufficient to pay our current expenses and preferred stock dividend. The

Company continues to rely on forms of capital financing to complete our development and drilling plans. To achieve this, we will utilize the skills of our board members in the fields of business development, capital acquisition, corporate visibility, oil and gas development, geology and operations.

Further, as opportunities for participation in profitable revenue producing projects come forward, 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 reducing the amount of variable costs, there is almost no way to reduce or offset our fixed expenses related to office expense, legal, accounting, transfer agent fees, Securities Act 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 this Report 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 financial statements. There can be no assurance that the actual results will not differ from those estimates.

Stock issuances

The Company has relied upon the issuance of shares of its common and preferred stock to fund much of the Company’s operations. Stock issued for services is valued at the market price of the Company’s stock at the date of grant. Compensation related to the issuance of stock options to employees and directors is recorded at the intrinsic value of the options, which is the market price of the Company’s common stock.The Company’s common stock issued to consultants is recorded at the market price of the Company’s common stock at the measurement date.

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. Our significant accounting policies are more fully described in Note 2 of Notes to the Consolidated Financial Statements. 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.

Principles of Consolidation

The consolidated financial statements include the accounts of Arête Industries, Inc. and its subsidiary Aggression Sports, Inc. (inactive). All the significant inter-company balances and transactions are eliminated in the consolidation. The Company is reporting its consolidated operations under the guidance of ASC 810 for consolidated companies.

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.

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 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 stock-based payment awards.

Cash Equivalents

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

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

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.

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.

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.

The Company reviews its 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 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 on a field-by-field basis using the unit-of-production method. Natural gas is converted to barrel equivalents, bble, at the rate of six Mcf to one barrel. 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

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.

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

The nature of our operations and the locations in which we operate create certain challenges and risks to us. These challenges and risks are discussed in Item I of this Annual Report. However certain of these factors are especially important to this discussion and to understanding our results of operations, financial condition and cash flows, and the reasons why historical financial results may not be indicative of our future operating performance.

Key selected financial and operating data for the years ended December 31, 2009 and 2010 are as follows. All references to the earnings per share are on a diluted basis. The following consolidated Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the financial statements.

Oil and Gas Producing Activities

On July 29, 2011, we entered into a purchase and sale agreement which resulted in our 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 Five-Month 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 Five-Month 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 Five-Month Period. Lease Operating Expense averaged $27.43 per Barrel of Oil Equivalent (“BOE”) whereby six Mcf of gas are equal to one barrel of oil. Many of the wells included in our acquisition 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 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.

One of the properties purchased on July 29, 2011 was sold to an unrelated purchaser on August 23, 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. We applied the proceeds to the payments due under the July 29, 2011 Amended Agreement. 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) 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 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 within the next three years to fully exploit the value of the properties and the gas gathering system. 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. 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 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

Income from operations for the fiscal year ended December 31, 2011 was $774,578 as compared to a net (loss) from operations of ($927,304) for the fiscal year ended December 31, 2010. The increase in income from operations of $1,711,882 includes the items discussed above relating to the oil and natural gas operations and other operating costs.

Net income (loss)

Net income for the fiscal year ended December 31, 2011 was $495,266 which includes ($391,606) interest expense, income from extinguishment of debt income and interest income of $112,994 as compared to a net loss of ($852,612) for the fiscal year ended December 31, 2010, which includes $47,191 interest expense, income from extinguishment of debt income and interest income of $121,883.

Liquidity and Capital Resources

The Company had a working capital deficit as of December 31, 2011 of $1,667,440. This compares to a working capital deficit of $2,110,583 in the fiscal year ended December 31, 2010. During the 12-month period ended December 31, 2011 an aggregate of 2,791,841 shares of common stock were issued for aggregate consideration of $3,292,251 (avg. $1.18 per share). This compares to the 12-month period ended December 31, 2010 an aggregate of 40,000 shares of common stock were issued for aggregate consideration of $24,500 (avg. $0.61 per share).

Management believes that the Company may experience difficulty raising additional equity capital or debt due to our lack of capital and operating history. During 2011, the Company eliminated a substantial amount of its outstanding debt and achieved operating revenue from its oil and natural gas operations. However, the chances of success of raising additional equity or debt capital are uncertain.

Unless and until it achieves success in its proposed operating activities, of which there is no assurance, the Company may continue to be required to issue further stock to pay executives, consultants and other employees, which would likely have a continuing dilutive effect on other shareholders of the Company. Failure of the Company to acquire additional capital in the form of either debt or equity capital or achieve meaningful revenue from proposed operations will most likely impair the ability of the Company to meet its obligations in the near-term and long-term.

The Company had a stockholder’s equity at December 31, 2011 of $6,978,041. This is compared to stockholder’s (deficit) at December 31, 2010 of ($1,832,847). The stockholder’s equity increased due to the Company’s issuance of common stock of $3,292,251, issuance of net preferred stock of $5,023,371, and net income of $495,266.

The Company has net cash (used) for operating activities for the year ended December 31, 2011 of $(754,244) as compared to net cash (used) by operating activities of $(213,124) for the year ended December 31, 2010.

The Company had net cash (used) in investing activities of ($1,131,670) for the year ended December 31, 2011, that includes net expenditures for oil and natural gas properties, as compared to no net cash (used) in investment activities for the year ended December 31, 2010.

The Company had net cash provided by financing activities of $2,089,490, that included net cash from loans of $(3,242,381) net, common stock of $203,500, and preferred stock of $5,023,371 for the year ended December 31, 2011 and had net cash provided by financing activities of $215,000 for the year ended December 31, 2010.

At December 31, 2011, the Company had no material commitments for capital expenditures.

Contractual Obligations and Commercial Commitments


	Payments Due by Period
Contractual Obligations	Total		2012		2013-2014		2015-2016		Thereafter
Long-term Debt	$	—	$	—	$	—	$	—	$	—
Capital Leases	$	—	$	—	$	—	$	—	$	—
Operating Leases	$	8,550	$	2,850	$	1,200	$	1,200	$	3,300

Off-Balance Sheet Arrangements

We do not currently have any off balance sheet arrangements falling within the definition of Item 303 of Regulation S-B.

Inflation

To date, inflation has not had a material impact on our operations.

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.

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 AND 2011

WITH

REPORTS OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES


INDEX

Report of Independent Registered Public Accounting Firm			31

Report of Independent Registered Public Accounting Firm			32

Consolidated Financial Statements:

Consolidated Balance Sheet – December 31, 2010 and 2011			33

Consolidated Statement of Operations – For the years ended December 31, 2010 and 2011			34

Consolidated Statement of Stockholders’ (Equity) Deficit – For the years ended December 31, 2010 and 2011			35

Consolidated Statement of Cash Flows – For the years ended December 31, 2010 and 2011			36

Notes to Consolidated Financial Statements			37

CAUSEY DEMGEN & MOORE INC.

1801 California Street, Suite 4650

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 INC.

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.

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 $5,225,000 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.

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
Gain of sale of oil and natural gas properties		—			2,479,934
Gas gathering income		167,625			45,638

Total revenues		167,625			3,530,721

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 income (loss)		(927,304	)		774,578
Other income (expense):
Gain on extinguishment of debt		121,870			111,690
Interest income		13			604
Interest expense		(47,191	)		(391,606	)

Total other income (expense)		74,692			(279,312	)

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 shareholders	$	(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.

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		—			1,156,251
Settlement of liabilities to related parties at $0.88 per share							770,000		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.

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 inome (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.

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

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.

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.

Gas gathering system, furniture and equipment

Oil and Gas Producing Activities

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, Bble, 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.

Asset Retirement Obligations

Revenue Recognition

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

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.

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 to common stock at an exchange price of $3.30 per common share.

New Accounting Pronouncements

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 owned by a director of the Company, Charles B. Davis. The consideration for the purchase was determined by arms-length 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 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)

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.

(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. 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. Certain properties were sold on August 23, 2011 and the Company received $5,101,047 for its share of the proceeds on the sale. 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 these sales did not qualify for discontinued operations reporting. All gains and losses recognized from property sales are included in other operating revenues in the Consolidated Statements of Operations.

4.	Stock transactions

Common stock

Stock issuances:

During the year ended December 31, 2010, 4,000,000 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, 3,500,000 shares of common stock were issued to consultants and for fees.

The Company has authorized shares of 500,000,000 shares of Common Stock and has issued 497,155,754 shares of Common Stock. They will have to increase their authorized common stock to meet the obligations described above by paying with Common Stock. The total of Common Stock obligated is 153,597,273 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 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.

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”). 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. The following are the advances from the officers and directors:

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 320,000 shares 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.

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 infull 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.

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		—		637,176
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	$	—	$	639,842

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.

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	$	3,022,400		$	5,786,870

Net income (loss)	$	(1,557,527	)	$	653,494

Net income (loss) applicable to common stockholders	$	(1,557,527	)	$	457,494

Earnings per share:
Basic	$	(0.31	)	$	0.07

Diluted	$	(0.31	)	$	0.07

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. 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.

15.

Supplementary Oil and Gas Information (unaudited)

Costs Incurred. Costs incurred in oil and gas property acquisition, 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		—		10,942,751
Exploration costs		—		—
Development costs		—		—
Asset retirement obligation		—		639,176

Total costs incurred	$	—	$	11,075,696

Depletion per bble 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 for the year ended December 31, 2011:


	Oil (Bbl)			Gas (Mcf)			Equivalent (Bble)
Balance, December 31, 2010		—			—			—
Purchases of oil and gas reserves in place		495,159			2,007,328			829,714
Sale of oil and gas reserves in place		(110,151	)		(1,141,550	)		(300,409	)
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.

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		(4,623,201	)

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

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A(T) CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934 (“Exchange Act”), we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer (“CEO”) and Acting Chief Financial Officer (“CFO”), of the effectiveness of our disclosure controls and procedures (as defined under Rule 13a-15(e) under the Exchange Act) as of the end of the period covered by this report. Based upon that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in the reports that the we file or submit under the Exchange Act, is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our CEO and CFO, as appropriate, to allow timely decisions regarding required disclosure.

Management’s Report on Internal Control Over Financial Reporting.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) under the Securities Exchange Act, as amended. Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2011. In making this assessment, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control-Integrated Framework. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis. We have identified the following material weaknesses.

As of December 31, 2011, we did not maintain effective controls over the control environment. We have not developed and effectively communicated to our employees its accounting policies and procedures. This has resulted in inconsistent practices. Further, the Board of Directors does not currently have any independent members that qualifies as an audit committee financial expert as defined in Item 407(d) (5) (ii) of Regulation S-B. Since these entity level programs have a pervasive effect across the organization, management has determined that these circumstances constitute a material weakness.

As of December 31, 2011, we did not maintain effective controls over financial statement disclosure. Specifically, controls were not designed and in place to ensure that all disclosures required were originally addressed in our financial statements. Accordingly, management has determined that this control deficiency constitutes a material weakness.

Changes in Internal Control Over Financial Reporting.

The annual report does not include an attestation report of the company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the company’s registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the company to provide only management’s report in this annual report.

There have been no changes in our internal control over financial reporting during the latest fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None

PARTIII

ITEM 10. Directors, Executive Officers and Corporate Governance

Charles L. Gamber (61) Director and Secretary.

Mr. Gamber joined the Company’s Board of Directors in September of 2003, serving as an independent Director, and as a member of the Company’s Audit and Compensation Committees. Mr. Gamber is currently the President and CEO of 86 Phoenix, LLC, a real estate and property development corporation doing business in Colorado. Mr. Gamber has also served as a Director of Net Commerce, Inc., a public company from 2001 to the present. He has served as a consultant for Donald W. Prosser, PC and VCG Holding Corp., a publicly held company with an emphasis in areas of organizational needs, financial projects, and business development. Mr. Gamber has 14 years of sales and service experience in the restaurant industry. He has owned and operated All America Auto Transport of Colorado for 6 years, and was with Toyota Motor Distributors for 5 years, leaving them as a District Sales Manager to pursue his own interests. Mr. Gamber received a bachelor’s degree in Business Administration from Western State College in 1973.

John R. Herzog (65) Director and Acting Chief Financial Officer.

Mr. Herzog joined the Company’s Board of Directors in September of 2003, serving as independent Director, and as a member of the Company’s Audit, Nomination and Compensation Committees. He brings a depth of concrete practical and entrepreneurial experience in business start-ups, turn-arounds, technology oriented business and technology development projects. 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, and generated an additional $1 million per year of revenue for this company. From 2000 to 2001, he served as director of IT for Anything Internet, Inc., a public company. Since 2001, Mr. Herzog has been President of Business Information Systems, Inc., developing applications, consulting on software development, business systems, and programming. Mr. Herzog has also served as a Director of Net Commerce, Inc., a public company from 2001 to the present. 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.

William W. Stewart (50) Director.

Mr. Stewart joined the board of directors on December 19, 2001 at the time the Company entered into a Letter of Intent with Mr. Stewart to form a subsidiary corporation to pursue acquisition and management of minor league sports franchises. 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; Nomination 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. He has consulted with many small companies, both public and private, on capital formation and mergers and acquisitions. 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. Mr. Stewart was born in The Pas, Manitoba, Canada. 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.

Donald W. Prosser (60) Chairman and Chief Executive Officer.

Mr. Prosser joined the Company’s Board of Directors in September of 2003, serving as Director and member of the Company’s Compensation, Audit, and Compensation Committees. He has been designated as the Company’s Financial Expert under the Sarbanes-Oxley Act. Mr. Prosser is a professional CPA, specializing in tax and securities accounting, and has represented a number of private and public 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 public company publishing high school athletic information and providing 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. From 2001 to the present, Mr. Prosser serves as CFO and Director for Net Commerce, Inc, a public company selling internet services. Since November 2002 through June 2008, Mr. Prosser serves as CFO of VCG Holding Corp., a public company engaged in the business of acquiring, owning and operating nightclubs, which provide premium quality entertainment, restaurant and beverage services in an up-scale environment to affluent patrons. His accounting firm performs accounting service for VCG Holding Corp.

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).

Charles B. Davis (55) Director

Mr. Davis joined Arête’s Board of Directors in 2006, and serves as a member of the Company’s Nominating and Compensation Committees. With over 25 years of experience in the oil and gas industry, Mr. Davis is a valuable addition to the board of the Company. 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 till August 1988, Mr. Davis did consulting work related to well site operations. Then in August 1988 Mr. Davis joined DNR Oil & Gas Inc. as president, running 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.

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.

Audit Committee.

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 as defined by Item 401(h) of Regulation S-B under the Securities Act and is not independent within the meaning of Item 7(d)(3)(iv) of Schedule 14A under the Exchange Act.

Nominating Committee.

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.

The Compensation Committee was established in 2003. It administers our incentive plans, sets policies that govern executives’ annual compensation and long-term incentives, and reviews management performance, compensation, development and succession. The Compensation Committee met one time during the year 2011 to review, among other things, compensation for the officers and directors.

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

The Company files reports under Section l5 (d) of the Securities Exchange Act of 1934; accordingly, directors, executive officers and 10% stockholders are not required to make filings under Section 16 of the Securities Exchange Act of 1934.

CODE OF BUSINESS CONDUCT AND ETHICS

Objective

The corporate philosophy of Arête Industries, Inc. and its subsidiaries is that good ethics and good business conduct go hand in hand. The conduct and values of its Company associates including directors, employees and consultants reflect upon the Company. These business standards provide a general framework of values and obligations that should be adhered to at all times. Corporate standards guide each Company associate’s 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 the Code of Business Conduct and Ethics (the “Code”) supports and reflects our statutory compliance with such laws.

We have adopted a Code of Ethics within the meaning of Item 406(b) of Regulation S-B of the Securities Act of 1933, as amended. The Code applies to our principal executive officer, principal financial officer, principal accounting officer or controller, and persons performing similar functions. Upon written request, we will mail you a free copy of our Code. Please mail your request to the following address: Arête Industries Inc., P.O. Box 141, Westminster, Colorado 80036.

ITEM 11. EXECUTIVE COMPENSATION

Summary Compensation Table

The following table sets forth the aggregate compensation paid by the Company for services rendered during the last two completed fiscal years:

SUMMARY COMPENSATION TABLE

Long Term Compensation

Annual Compensation

Awards

Payouts

(a)

(b)

(c)

(d)

(e)

(f)

(g)

(h)

(i)

Name and Principal Position

Year or
Period
Ended

Salary
$

Bonus
$

Other Annual
Compensation

Restricted
Stock
Awards
($)

Option/
SAR’s
(#)

LTIP
Payouts
($)

All Other
Compensation
($)

Charles Gamber,

Secretary, Director

12/31/11

12/31/10

12/31/09

$ -0-

$ -0-
$ -0-

John Herzog,

Acting CFO, Director

12/31/11

12/31/10

12/31/09

$ -0-

$ -0-
$ -0-

Donald W Prosser

CEO, and Chairman

12/31/11

12/31/10

12/31/09

$ -0-

$ -0-
$ -0-

Charles Davis

COO and Director

12/31/11

12/31/10

12/31/09

$ -0-

$ -0-
$ -0-

Option/SAR Grants Table

Option/SAR Grants in Last Fiscal Year

Individual Grants

There were no grants of options of stock to officers in the fiscal year ended December 31, 2011.

Aggregated Option/SAR Exercises and Fiscal Year-End Option/SAR Value Table.

Aggregated Option/SAR Exercises in Last Fiscal Year

And FY-End Option/SAR Values


(a)	(b)	(c)	(d)	(e)
Name	on Exercise (#)	Value Realized ($)	Number of Securities Underlying Unexercised Options/SAR’s at Shares Acquired Exercisable/ Unexercisable	Value of Unexercised In-the-Money Options/SAR’s at FY-End Exercisable/ Unexercisable
None	0	$-0-	-0-	$-0-

Compensation of Directors.

The directors are compensated for consulting services and may be reimbursed for their expenses in attending formal meetings of the board of directors. The following is the director’s compensation for the fiscal year ended December 31, 2011.


Charles Gamber	$	24,000	(2)
William Stewart	$	24,000	(2)
John Herzog	$	24,000	(2)
Donald W Prosser	$	99,000	(1)
Charles Davis	$	39,000	(3)

(1)	includes work related to the audit committee, accounting, and the SEC filings;

(2)	includes payment of officers compensation;

(3)	includes payment of officers compensation and oil and natural gas opertations.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Security Ownership of Management


Title of Class	Name and Address of Beneficial Owner Directors and Executive Officers	Amount and Nature of Beneficial Ownership		Percent of Class
Common Stock	William W. Stewart Director c/o P.O. 141 Westminster, Colorado 80036	Direct:	71,104	0.916%(1)

Common Stock	Donald W Prosser CEO/Chairman c/o P.O. 141 Westminster, Colorado 80036	Direct:	690,731	8.896(2)

Common Stock	Charles L. Gamber Director/Secretary c/o P.O. 141 Westminster, Colorado 80036	Direct:	90,410	1.164%(3)

Common Stock	John R. Herzog Director/ Acting CFO c/o P.O. 141 Westminster, Colorado 80036	Direct:	268,029	3.452%(4)

Common Stock	Charles Davis Director/COO c/o P.O. 141 Westminster, Colorado 80036	Direct:	689,854	8.885%(5)

Common Stock	Directors and Executive Officers as a Group	Total:	1,810,128	23.57%(6)

(1)	Includes Directly Owned of 71,104 shares;

(2)	Includes Directly Owned of 690,731 shares;

(3)	Includes Directly Owned of 90,410 shares;

(4)	Includes Directly Owned of 268,029 shares;

(5)	Includes Directly Owned of 689,854 shares;

(6)	Includes Directly Owned of 1,810,128 common shares.

Percentage calculated based on 7,764,476 common shares outstanding.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Transactions with Management and Others

During the fiscal years ended December 31, 2010 and December 31, 2011, transactions occurred with directors and executive officers relating to cash and non-cash compensation which are disclosed in the discussion and footnotes to Item 10 of this Report, Executive Compensation, and Item 11, Security Ownership of Certain Beneficial Owners and Management which are incorporated herein by reference. (See also: Notes 3, 4, 5 and 6, Notes to Audited Financial Statements.)

On September 13, 2006 we purchased the TOP Gathering System located in Campbell County, Wyoming for $330,000 cash from PRB Energy, Inc. The TOP 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. The pipeline services producers of coal-bed methane in the Powder River Basin and is currently gathering from 33 wells operated by an independent natural gas company, transporting approximately 1.25 million cubic feet of gas per day. The gathering system has a current throughput capacity of approximately 4 to 30 million cubic feet (“MMcf”) of gas per day based on the compression attached to the pipeline. Our current fees of transportation will average $0.80 per thousand cubic feet (“Mcf”) and gathering fees are subject to contracts that expire 2012. Arête is in negotiations with the well owners and leaseholders of the current wells attached to the pipeline to purchase or participate in the development of the other gas zones in the region. The pipeline has capacity of three times as much gas as is presently being delivered, based on current compression, and developing the present leases would help fill that capacity. The funds of $400,000 in cash for the pipeline and related costs have been provided by two directors of the Company and an independent third party. The funds provided to the Company were as follows: $200,000 Director & Chairman Donald W. Prosser, $75,000 Director and Secretary William Stewart, and $125,000 Director Charles Davis. No formal plan has been finalized on the repayment of these funds. The Company anticipates that the debt structure will be in the form of a convertible note secured by the assets of the pipeline. The rate of interest is 9.6% and the terms of the conversion are still being negotiated. These notes were converted to 62,500 shares of Common stock at a rate of $8.00 per share in May 2011.

Donald W. Prosser pledged 215,000 shares of his Common stock to individuals in exchange for a loan of $215,000 with no interest due in May 2011. The advance was used as working capital.

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 320,000 shares of his stock 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 will be repaid in equal shares when the Company has shares available to repay the stock and will be adjusted in the event of stock reverse on a prorate basis.

The Company owes a director for services related to the operations of the pipeline business and purchase of oil & gas property. The board of directors has 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 being carried as prepaid expenses. The contract will be paid in shares of common stock when the Company has shares available to pay the contract and will be adjusted in the event of stock reverse on a prorate basis.

The Company owes its directors for services for part of 2008, 2009, and 2010. They are accruing $98,000 during fiscal 2010 to be paid in the future with 66,023 shares of Common Stock valued at $0.0148 per share. The Company paid Mr. Gamber 5,000 shares of Common stock as part of his 2008 fee valued at $2,450.

The Company paid Donald W Prosser $22,050 (35,000 shares of Common Stock) for due diligence on the proposed acquisition and work on financing for the year ended December 31, 2010. The Company also paid Mr. Prosser $3,000 for the years ended December 31, 2010 and 2011 for the office, meeting and storage space at 7260 Osceola Street, Westminster, CO 80030.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The following relate to aggregate fees billed for the last two fiscal years by the Company’s principal accountants concerning the Company’s: (1) audit; (2) for assurance and services reasonably related to the audit; (3) for tax compliance, advice, and planning; and (4) for other fees provided by the principal accountant for the following:

1.	Audit Fees. $10,000 (2011)

2.	Audit-Related Fees. $-0- (2011)

3.	Tax Fees. $-0- (2011)

4.	All Other Fees. $-0- (2011) Reading of the subsequent events procedures and Form 8-K.

5. (i) The Company’s Audit Committee’s pre-approval policies and procedures (described in paragraph (c)(7)(i) of Rule 2-01 of Regulation S-X), are:

Audit Committee Pre-Approval Policies and Procedures

As set forth in its charter, our Audit Committee has the sole authority to pre-approve all audit and non-audit services provided by our independent auditor. All services performed by Causey Demgen and Moore Inc. in 2011 were pre-approved by our Audit Committee. Having considered whether the provision of the auditors’ services other than for the annual audit and quarterly reviews is compatible with its independence, the Audit Committee has concluded that it is.

1.	Audit Fees. $13,000 (2010) $28,250 (2011)

2.	Audit-Related Fees. $-0- (2010 & 2011)

5.	Tax Fees. $-0- (2010 & 2011)

6.	All Other Fees. $-0- (2010 & 2011) Reading of the subsequent events procedures and Form 8-K.

5. (i) The Company’s Audit Committee’s pre-approval policies and procedures (described in paragraph (c)(7)(i) of Rule 2-01 of Regulation S-X), are:

Audit Committee Pre-Approval Policies and Procedures

As set forth in its charter, our Audit Committee has the sole authority to pre-approve all audit and non-audit services provided by our independent auditor. All services performed by Ronald R. Chadwick PC CPA in 2009 and 2010 were pre-approved by our Audit Committee. Having considered whether the provision of the auditors’ services other than for the annual audit and quarterly reviews is compatible with its independence, the Audit Committee has concluded that it is.

The Audit Committee on an annual basis reviews audit and non-audit services performed by the independent auditors. All audit and non-audit services are pre-approved by the Audit Committee, which considers, among other things, the possible effect of the performance of such services on the auditors’ independence. All requests for services to be provided by the independent auditor, which must include a description of the services to be rendered and the amount of corresponding fees, are submitted to the Chief Financial Officer. The Chief Financial Officer authorizes services that have been pre-approved by the Audit Committee. If there is any question as to whether a proposed service fits within a pre-approved service, the Audit Committee chair is consulted for a determination. The Chief Financial Officer submits requests or applications to provide services that have not been pre-approved by the Audit Committee, which must include an affirmation by the Chief Financial Officer and the independent auditor that the request or application is consistent with the SEC’s rules on auditor independence, to the Audit Committee (or its chair or any of its other members pursuant to delegated authority) for approval.

(ii) 100 per cent of the fees billed by the principal accountant were approved by the Audit Committee (described in paragraph (c)(7)(i)(C) of Rule 2-01 of Regulation S-X).

6. The percentage (if over 50%) of hours expended on the principal accountant’s engagement to audit the Company’s financial statements for the most recent fiscal year done by persons other than the principal accountant’s full-time, permanent employees, was: Not applicable

PART IV

ITEM 15. EXHIBITS


Exhibit No.	Description	Ref.No

EX - 3.1	Restated Articles of Incorporation with Amendment adopted by shareholders on September 1, 1998.		1

EX - 3.2	Bylaws adopted by the Board of Directors on October 1, 1998.		1

EX - 3.3	Bylaws adopted by the Board of Directors on March 15, 2011.		1

EX - 4.1	Designation of Class A Preferred Stock dated February 26, 2001.		1

EX - 4.2	Designation of Series 1 Convertible Preferred Adopted November 19, 2001		1

EX - 4.3	Designation of Series 2 Convertible Preferred Adopted December 19, 2001.		1

EX - 10.1	2003 Omnibus Incentive Stock Compensation Plan Adopted, August 21, 2003		2

EX - 10.2	2004 Omnibus Incentive Stock Compensation Plan Adopted, August 4, 2004		3

EX - 10.3	Purchase agreement with PRB for purchase of pipeline		4

EX - 21	Subsidiaries of the Registrant		5

EX - 23	Consent from Ryder Scott

EX - 31.1	Certification of CEO Pursuant to 18 U.S.C, Section 7241, as adopted and Section 302 of the Sarbanes-Oxley Act of 2002		5

EX - 31.2	Certification of CFO Pursuant to 18 U.S.C, Section 7241, as adopted and Section 302 of the Sarbanes-Oxley Act of 2002		5

EX - 32.1	Certification of CEO Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002		5

EX - 32.2	Certification CFO Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002		5

EX - 99.1	Report from Ryder Scott		5

EX - 101.INS	XBRL Instance Document		6

EX - 101.SCH	XBRL Taxonomy Extension Schema Document		6

EX - 101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document		6

EX - 101.LAB	XBRL Taxonomy Extension Label Linkbase Document		6

EX - 101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document		6

EX - 101.DEF	XBRL Taxonomy Extension Definition Linkbase Document		6

Notes to Exhibits:

1. These documents and related exhibits have been previously filed with the Securities and Exchange Commission, and by this reference are incorporated herein.

2. Incorporated by reference to Exhibit 10.1 to Current Report on Form 8-KSB filed on September 4, 2003.

3. These documents and related exhibits have been previously filed under the Company’s periodic reports for periods ended during the fiscal year 12/31/04 and are incorporated herein by reference.

4. Incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on September 18, 2006.

5. Attached to this report on Form 10-K as Exhibits and incorporated herein by reference.

6. To be furnished by amendment.

SIGNATURES

In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


	Arête Industries, Inc.

April 16, 2012	By:	/s/ Donald W. Prosser
		Donald W. Prosser
		Chief Executive Officer

In accordance with the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.



/s/ Charles L. Gamber Charles L. Gamber	Secretary and Director	April 16, 2012

/s/ Donald W. Prosser Donald W. Prosser	Chairman of the Board and Chief Executive Officer	April 16, 2012

/ s/ John R. Herzog John R. Herzog	Acting Chief Financial Officer and Director	April 16, 2012

/s/William Stewart William Stewart	Director	April 16, 2012

EX-21 2 d313322dex21.htm SUBSIDIARIES OF THE REGISTRANT Subsidiaries of the Registrant

Exhibit 21

ANNUAL REPORT

FORM 10-K

FISCAL YEAR ENDED DECEMBER 31, 2010

Subsidiaries of the Registrant

Aggression Sports, Inc. Colorado Corporation org. 1998 (Inactive)

EX-23 3 d313322dex23.htm CONSENT FROM RYDER SCOTT Consent from Ryder Scott

Exhibit 23


		FAX (303) 623-4258

621 SEVENTEENTH STREET SUITE 1550 DENVER, COLORADO 80293 TELEPHONE (303) 623-9147

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

The undersigned hereby consents to the references to our firm in the form and context in which they appear in the Annual Report on Form 10-K of Arête Industries, Inc. for the year ended December 31, 2011. We hereby further consent to the use of information contained in our reports setting forth the estimates of revenues from Arête Industries, Inc.’s oil and gas reserves as of December 31, 2011, and to the inclusion of our report dated April 13, 2012 as an exhibit to the Annual Report on Form 10-K of Arête Industries, Inc. for the year ended December 31, 2011.

\s\ Ryder Scott Company. L.P.

RYDER SCOTT COMPANY, L.P

Denver, Colorado

April 16, 2012

EX-31.1 4 d313322dex311.htm SECTION 302 CEO CERTIFICATION Section 302 CEO Certification

Exhibit 31.1

CERTIFICATION

I, Donald W. Prosser, certify that:

1. I have reviewed this annual report of Arête Industries, Inc.;

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

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

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

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

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

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

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

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

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

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

Date: April 16, 2012

/s/ Donald W. Prosser

Donald W. Prosser

Chief Executive Officer

EX-31.2 5 d313322dex312.htm SECTION 302 CFO CERTIFICATION Section 302 CFO Certification

Exhibit 31.2

CERTIFICATION

I, John R. Herzog, certify that:

1. I have reviewed this annual report of Arête Industries, Inc.;

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

Date: April 16, 2012

/s/ John R. Herzog

John R. Herzog

Acting Chief Financial Officer

EX-32.1 6 d313322dex321.htm SECTION 906 CEO CERTIFICATION Section 906 CEO Certification

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the annual report of Arête Industries, Inc. (the “Company”) on Form 10-K for the year ended December 31, 2011 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, Donald W. Prosser, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

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

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

/s/ Donald W. Prosser

Donald W. Prosser

Chief Executive Officer

Dated: April 16, 2012

A signed original of this written statement required by Section 906 has been provided to Arête Industries, Inc. and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2 7 d313322dex322.htm SECTION 906 CFO CERTIFICATION Section 906 CFO Certification

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the annual report of Arête Industries, Inc. (the “Company”) on Form 10-K for the year ended December 31, 2011 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, John R. Herzog, Acting Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

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

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

/s/ John R. Herzog

John R. Herzog

Acting Chief Financial Officer

Dated: April 16, 2012

EX-99.1 8 d313322dex991.htm REPORT FROM RYDER SCOTT Report from Ryder Scott

Exhibit 99.1


		FAX (303) 623-4258

621 SEVENTEENTH STREET SUITE 1550 DENVER, COLORADO 80293 TELEPHONE (303) 623-9147

April 13, 2012

Arête Industries, Inc.

P.O. Box 141

Westminster, CO 80036-0141

Gentlemen:

At your request, we have prepared an estimate of the proved and probable reserves, future production, and income attributable to certain leasehold interests of Arête Industries, Inc. (Arête) as of December 31, 2011. The subject properties are located in the states of Colorado, Kansas, Montana and Wyoming. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on April 13, 2012 and presented herein, was prepared for public disclosure by Arête in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. The properties evaluated by Ryder Scott represent 100 percent of the total net proved liquid hydrocarbon reserves, 100 percent of the total net proved gas reserves, 100 percent of the total net probable liquid hydrocarbon reserves and 100 percent of the total net probable gas reserves of Arête

The estimated reserves and future net income amounts presented in this report, as of December 31, 2011, are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized below.

SEC PARAMETERS

Estimated Net Reserves and Income Data

Certain Leasehold Interests of

Arête Industries, Inc.


	As of December 31, 2011
	Proved
	Developed Producing		Undeveloped		Total Proved
*Net Remaining Reserves*
Oil/Condensate – Barrels		290,038		84,980		375,018
Gas – MCF		604,476		222,825		827,301

*Income Data, $*
Future Gross Revenue	$	26,565,601	$	7,789,826	$	34,355,427
Deductions		11,173,982		2,356,514		13,530,496

Future Net Income (FNI)	$	15,391,619	$	5,433,312	$	20,824,931
Discounted FNI @ 10%	$	7,584,747	$	3,280,698	$	10,865,445

Arête Industries, Inc.

April 13, 2012

Page 2


	Total Probable Undeveloped
*Net Remaining Reserves*
Oil/Condensate – Barrels		6,693
Gas – MCF		222,825

*Income Data, $*
Future Gross Revenue	$	1,230,112
Deductions		512,936

Future Net Income (FNI)	$	717,176

Discounted FNI @ 10%	$	429,061

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are reported on an “as sold” basis expressed in thousands of cubic feet (MCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package PHDWin Petroleum Economic Evaluation Software, a copyrighted program of TRC Consultants, L.C. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells, ad valorem taxes, recompletion costs and development costs. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income. Liquid hydrocarbon reserves account for approximately 87 percent of the total future gross revenue from proved reserves and gas reserves account for the remaining 13 percent of total future gross revenue from the proved reserves reported herein. Liquid hydrocarbon reserves account for approximately 46 percent of the total future gross revenue from probable reserves and gas reserves account for the remaining 54 percent of total future gross revenue from the probable reserves reported herein. There are no possible reserves included in this evaluation.

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


	Discounted Future Net Income As of December 31, 2011
Discount Rate Percent	Total Proved		Total Probable
5	$	14,220,085	$	545,951
12	$	9,931,930	$	392,240
15	$	8,795,504	$	344,768
20	$	7,376,540	$	281,365

Arête Industries, Inc.

April 13, 2012

Page 3

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

Reserves Included in This Report

The proved and probable reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10 (a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report. The various reserve status categories are defined under the attachment entitled “Petroleum Reserves Definitions” in this report.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The gas volumes included herein do not attribute gas consumed in operations as reserves.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves, and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Arête’s request, this report addresses only the proved and probable reserves attributable to the properties evaluated herein.

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”. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered”. Probable reserves are “those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered”.

The reserves included herein were estimated using deterministic methods and presented as incremental quantities. Under the deterministic incremental approach, discrete quantities of reserves are estimated and assigned separately as proved, probable or possible based on their individual level of uncertainty. Because of the differences in uncertainty, caution should be exercised when aggregating quantities of oil and gas from different reserves categories. Furthermore, the reserves and income quantities attributable to the different reserve categories that are included herein have not been adjusted to reflect these varying degrees of risk associated with them and thus are not comparable.

Reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved and probable reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved and probable reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

Arête Industries, Inc.

April 13, 2012

Page 4

Arête’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved and probable reserves actually recovered and amounts of proved and probable income actually received to differ significantly from the estimated quantities.

The estimates of reserves presented herein were based upon a detailed study of the properties in which Arête owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

Arête Industries, Inc.

April 13, 2012

Page 5

The proved and probable reserves for the properties included herein were estimated by performance methods or by analogy. The majority of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by the performance method. These performance methods include decline curve analysis which utilized extrapolations of historical production and pressure data available through December, 2011 in those cases where such data were considered to be definitive. In some cases, this data, while available, was not sufficient for extrapolation. In these cases, the analogy method was used. The data utilized in this analysis were supplied to Ryder Scott by Arête or obtained from public data sources and were considered sufficient for the purpose thereof.

One hundred percent of the proved and probable undeveloped reserves included herein were estimated by the analogy method. The analogy method utilized pertinent well data supplied to Ryder Scott by Arête or which we have obtained from public data sources that were available through December, 2011.

To estimate economically recoverable proved and probable oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data that cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved and probable reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Arête has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved and probable production and income, we have relied upon data furnished by Arête with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, production taxes, recompletion and development costs, product prices based on the SEC regulations and adjustments or differentials to product prices. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Arête. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved and probable reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved and probable reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

Arête Industries, Inc.

April 13, 2012

Page 6

Future Production Rates

For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Offset analogies and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Arête. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Hydrocarbon Prices

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

Ryder Scott determined the 1^st day of the month unweighted arithmetic average prices in effect on December 31, 2011. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “price reference” and the “average benchmark prices” used for the geographic area included in the report.

The product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were estimated by Ryder Scott based on information furnished by Arête.

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.

Arête Industries, Inc.

April 13, 2012

Page 7


Geographic Aea	Product	Price Reference	Average Benchmark Prices	Average Proved Realized Prices	Average Probable Realized Prices

United States	Oil/Condensate	WTI Cushing	$96.19/Bbl	$83.79/Bbl	$89.19/Bbl
United States	Gas	Henry Hub	$4.12/MMBTU	$5.84/MCF	$3.12/MCF

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

Costs

Operating costs for the leases and wells in this report were furnished by Arête and are based on the operating expense reports of Arête and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements. The operating costs furnished by Arête were reviewed by us for their reasonableness using information supplied by Arête for this purpose. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by Arête and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished by Arête were reviewed by us for their reasonableness using information supplied by Arête for this purpose. Arête’s estimates of zero abandonment costs after salvage value for onshore properties were used in this report. Ryder Scott has not performed a detailed study of the abandonment costs or the salvage value and makes no warranty for Arête’s estimate.

The proved and probable undeveloped reserves in this report have been incorporated herein in accordance with Arête’s plans to develop these reserves as of December 31, 2011. The implementation of Arête’s development plans as presented to us and incorporated herein is subject to the approval process adopted by Arête’s management. As the result of our inquires during the course of preparing this report, Arête has informed us that the development activities included herein have been subjected to and received the internal approvals required by Arête’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Arête. Additionally, Arête has informed us that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter their plans.

Current costs used by Arête were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

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

Arête Industries, Inc.

April 13, 2012

Page 8

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

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

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

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for preparing the reserves information discussed in this report, are included as an attachment to this letter.

Arête Industries, Inc.

April 13, 2012

Page 9

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Arête.

We have provided Arête with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Arête and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.


		Very truly yours, RYDER SCOTT COMPANY, L.P. TBPE Firm Registration No. F-1580

[SEAL]		\s\ Thomas E. Venglar Thomas E. Venglar, P.E. CO License No. 28846 Senior Petroleum Engineer

Approved:

\s\ James L. Baird, P.E.

James L. Baird, P.E.

Managing Senior Vice President

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Thomas E. Venglar was the primary technical person responsible for overseeing the estimate of the future net reserves and income.

Mr. Venglar, an employee of Ryder Scott Company L.P. (Ryder Scott) beginning in 2006, is a Senior Petroleum Engineer responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies. Before joining Ryder Scott, Venglar served in a number of engineering positions with Grynberg Petroleum Company and Anadarko Petroleum Corporation. For more information regarding Mr. Venglar’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Experience/Employees.

Venglar earned a Bachelor of Science degree in Petroleum Engineering from Texas A&M University in 1979 and is a registered Professional Engineer in the state of Colorado. He is also a member of the Society of Petroleum Engineers.

Based on his educational background, professional training and more than 30 years of practical experience in the estimation and evaluation of petroleum reserves, Venglar has attained the professional qualifications as a Reserves Estimator and Reserves Auditor as set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

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