10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

    x     Quarterly Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.

For the quarterly period ended June 30, 2012

Or

    ¨     Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.

For the transition period from          to         

Commission File 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, Colorado 80036

(Address of Principal Executive Offices) (Zip Code)

303-427-8688

(Registrant’s Telephone Number, Including Area Code)

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

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

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

Large accelerated filer	¨	Accelerated filer	¨
Non-accelerated filer	¨  (Do not check if a smaller reporting company)	Smaller reporting company	x

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

As of August 10, 2012, the Registrant had 7,979,803 shares of common stock issued and outstanding.

ARÊTE INDUSTRIES, INC.

Table of Contents

	Page
Part 1 - Financial Information
Item 1 - Financial Statements		1
Item 2 - Management’s Discussion and Analysis of Financial Condition and Results of Operations		14
Item 3 - Quantitative and Qualitative Disclosures about Market Risk		27
Item 4 - Controls and Procedures		27
Part 2 - Other Information
Item 1 - Legal Proceedings		28
Item 1A - Risk Factors		28
Item 2 - Sales of Unregistered Equity Securities and Use of Proceeds		28
Item 3 - Defaults upon Senior Securities		29
Item 4 - Mine Safety Disclosures		29
Item 5 - Other Information		29
Item 6 - Exhibits		29
Signatures		30

Part 1 – FINANCIAL INFORMATION

Item 1 - Financial Statements

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED BALANCE SHEETS

December 31, 2011 and June 30, 2012

	2011			2012
ASSETS
Current Assets:
Cash and equivalents	$	219,566		$	168,241
Receivable from DNR Oil & Gas, Inc.:
Oil and gas sales, net of production costs		165,283			106,957
Other		15,597			38,444
Prepaid expenses and other		207,338			147,874
Total Current Assets		607,784			461,516
Property and Equipment:
Oil and gas properties, at cost, successful efforts method:
Proved properties		9,056,032			9,219,558
Unevaluated properties		287,728			310,288
Natural gas gathering system		442,195			442,195
Furniture and equipment		22,522			22,522
Total property and equipment		9,808,477			9,994,563
Less accumulated depreciation, depletion and amortization		(525,154	)		(876,551	)
Net Property and Equipment		9,283,323			9,118,012
TOTAL ASSETS	$	9,891,107		$	9,579,528

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

1

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED BALANCE SHEETS, Continued

December 31, 2011 and June 30, 2012

	2011			2012
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable:
Payable to DNR Oil & Gas, Inc.:
Oil and gas property acquisition costs	$	826,791		$	291,616
Gas gathering operating costs		416,835			436,403
Operator fees and other		151,748			151,748
Unrelated parties		92,019			96,912
Notes and advances payable:
Directors and affiliates		109,319			245,950
Unrelated parties		250,000			250,000
Accrued interest expense		88,303			39,375
Director fees payable in common stock		90,000			30,000
Accrued consulting services payable in common stock		18,750			48,750
Current portion of asset retirement obligations		15,398			67,527
Other accrued costs and expenses		216,061			258,040
Total Current Liabilities		2,275,224			1,916,321
Long-Term Liabilities:
Acquisition costs payable to DNR Oil & Gas, Inc.		—			250,000
Asset retirement obligations, net of current portion		637,842			599,840
Total Long-Term Liabilities		637,842			849,840
Total Liabilities		2,913,066			2,766,161
Commitments and Contingencies (Note 3, 5 and 9)
Stockholders’ Equity:
Convertible Class A preferred stock; $10,000 face value per share, authorized 1,000,000 shares:
Series 1; authorized 30,000 shares, issued and outstanding 522.5 shares in 2011 and 2012, liquidation preference of $5,420,938 in 2011 and 2012		5,023,371			5,023,371
Series 2; authorized 2,500 shares, no shares issued and outstanding in 2011 and 2012		—			—
Common stock, no par value; authorized 499,000,000 shares, issued and outstanding 7,764,476 in 2011 and 7,979,803 in 2012		16,904,154			17,151,096
Accumulated deficit		(14,949,484	)		(15,361,100	)
Total Stockholders’ Equity		6,978,041			6,813,367
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	9,891,107		$	9,579,528

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

2

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS

For the Quarters and the Six-Months Ended June 30, 2011 and 2012

	Quarter Ended June 30:						Six-Months Ended June 30:
	2011			2012			2011			2012
Revenues:
Oil and natural gas sales	$	—		$	481,360		$	—		$	1,035,395
Sale of oil and natural gas properties		—			—			—			533,048
Gas gathering income		15,983			—			45,639			—
Total revenues		15,983			481,360			45,639			1,568,443
Operating Expenses:
Oil and gas producing activities:
Lease operating expenses		—			117,944			—			401,653
Production taxes		—			40,130			—			84,326
Depreciation, depletion, amortization and accretion		—			205,730			—			336,837
Gas gathering:
Cost of operations:
Related Party		10,204			—			30,815			—
Unrelated parties		33,415			3,660			80,558			7,320
Depreciation		11,055			11,055			22,110			22,110
General and administrative expenses:
Director fees		30,000			30,000			60,000			60,000
Investor relations		84,782			84,227			225,322			130,031
Acquisition investigation and due diligence		472,978			—			500,478			—
Legal, auditing and professional services		42,430			28,562			85,969			77,642
Consulting and executive services:
Related parties		56,375			155,750			112,750			316,500
Unrelated parties		83,610			55,059			161,852			76,504
Other administrative expenses		8,970			29,249			25,695			42,795
Depreciation		—			142			—			285
Total operating expenses		833,819			761,508			1,305,549			1,556,003
Operating income (loss)		(817,836	)		(280,148	)		(1,259,910	)		12,440
Other income (expense):
Interest income		139			65			279			220
Interest expense		(22,697	)		(14,556	)		(34,442	)		(32,401	)
Loss before income taxes		(840,394	)		(294,639	)		(1,294,073	)		(19,741	)
Income tax benefit (expense)		—			—			—			—
Net loss	$	(840,394	)	$	(294,639	)	$	(1,294,073	)	$	(19,741	)
Net Loss Applicable to Common Stockholders:
Net loss	$	(840,394	)	$	(294,639	)	$	(1,294,073	)	$	(19,741	)
Accrued preferred stock dividends		—			(195,938	)		—			(391,875	)
Net loss applicable to common stockholders	$	(840,394	)	$	(490,577	)	$	(1,294,073	)	$	(411,616	)
Earnings (Loss) Per Share Applicable to Common Stockholders:
Basic	$	(0.12	)	$	(0.06	)	$	(0.22	)	$	(0.05	)
Diluted	$	(0.12	)	$	(0.06	)	$	(0.22	)	$	(0.05	)
Weighted Average Number of Common Shares Outstanding:
Basic		6,985,000			7,788,000			5,995,000			7,776,000
Diluted		6,985,000			7,788,000			5,995,000			7,776,000

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

3

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

For the Six-Months Ended June 30, 2012

	Class A Preferred Stock				Common Stock				Accumulated Deficit			Total
	Shares		Amount		Shares		Amount
Balances, December 31, 2011		522.5	$	5,023,371		7,764,476	$	16,904,154	$	(14,949,484	)	$	6,978,041
Issuance of common stock for Board of Directors’ fees		—		—		65,605		120,000		—			120,000
Issuance of common stock to related parties for consulting services		—		—		135,972		110,000		—			110,000
Issuance of common stock to unrelated parties:
For accrued interest		—		—		7,750		10,462		—			10,462
For consulting services		—		—		6,000		6,480		—			6,480
Preferred stock dividends declared		—		—		—		—		(391,875	)		(391,875	)
Net loss		—		—		—		—		(19,741	)		(19,741	)
Balances, June 30, 2012		522.5	$	5,023,371		7,979,803	$	17,151,096	$	(15,361,100	)	$	6,813,367

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

4

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Six-Months Ended June 30, 2011 and 2012

	2011			2012
Cash Flows from Operating Activities:
Net loss	$	(1,294,073	)	$	(19,741	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		22,110			355,132
Accretion of discount on asset retirement obligations		—			4,100
Gain on sale of oil and gas properties		—			(533,048	)
Common stock issued in exchange for services		734,084			246,942
Common stock issued in exchange for accrued interest		—			10,462
Changes in operating assets and liabilities:
Accounts receivable		11,832			(76,179	)
Prepaid expenses and other		—			60,714
Accounts payable		(5,721	)		24,461
Accrued costs and expenses		72,991			2,590
Net cash provided by (used in) operating activities		(458,777	)		75,433
Cash Flows from Investing Activities:
Capital expenditures for oil and gas properties		(500,000	)		(646,269	)
Proceeds from sale of oil and gas properties		—			1,108,709
Contingent consideration paid to DNR under sharing arrangement		—			(282,704	)
Net cash provided by (used in) investing activities		(500,000	)		179,736
Cash Flows from Financing Activities:
Proceeds from notes and advance payable		870,000			400,000
Principal payments on notes payable		(9,256	)		(264,619	)
Payment of dividends on preferred stock		—			(391,875	)
Proceeds from sale of common stock		103,500			—
Payment of preferred stock offering costs		—			(50,000	)
Net cash provided by (used in) financing activities		964,244			(306,494	)
Net increase (decrease) in cash and equivalents		5,467			(51,325	)
Cash and equivalents, beginning of period		15,990			219,566
Cash and equivalents, end of period	$	21,457		$	168,241
Supplemental Disclosure of Cash Flow Information:
Cash paid for interest	$	17,755		$	83,827
Cash paid for income taxes	$	—		$	—
Supplemental Disclosure of Non-cash Investing and Financing Activities:
Conversion of notes payable to 897,500 shares of common stock	$	1,335,000		$	—
Advances from officers and directors and prepaid fees to consultants paid by the issuance of common stock	$	1,019,667		$	—
Payable to DNR for acquisition of oil and gas properties	$	—		$	291,616
Asset retirement obligations assumed upon sale of oil and gas properties	$	—		$	16,411
Increase in oil and gas properties due to revision of asset retirement obligations	$	—		$	26,437

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

5

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2012

1. Organization and Nature of Operations

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

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

2. Summary of Significant Accounting Policies

Basis of presentation

The accompanying unaudited consolidated financial statements have been prepared by the Company. In the opinion of management, the accompanying unaudited financial statements contain all adjustments (consisting of only normal recurring accruals) necessary for a fair presentation of the financial position as of December 31, 2011 and June 30, 2012, and the results of operations, changes in stockholders’ equity, and cash flows for the quarters and the six-months ended June 30, 2011 and 2012. Operating results for the interim periods presented are not necessarily indicative of the results that may be expected for a full year. The Company’s 2011 Annual Report on Form 10-K includes certain definitions and a summary of significant accounting policies and should be read in conjunction with this Form 10-Q. Except as disclosed herein, there have been no material changes to the information disclosed in the notes to the consolidated financial statements included in the Company’s 2011 Annual Report on Form 10-K.

Use of estimates

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

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

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.

6

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2012

Reclassifications

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

Earnings per share

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

New Accounting Pronouncements

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

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

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

7

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2012

3. Acquisitions and Disposition of Oil and Gas Properties

Acquisitions

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

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

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

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

Properties:
Rex Lake/ Big Hollow (WY)	$	511,025	(b)
Kansas		2,152,216	(a)
Montana		98,179	(b)
Wyoming		2,733,773	(b)
Buff (WY)		611,211	(b)
Colorado		2,507,678	(a)
Total Working Interest Properties		8,614,802
Separate Interests		2,385,918	(d)
	$	11,000,000	(c)

8

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2012

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

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

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

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

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

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

(c) 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 final purchase allocation under generally accepted accounting principles.

(d) With respect to the Separate Interests, a formal closing and transfer of title was not required, and did not occur, in order for the Company to realize its proceeds related to the sale of the Separate Interests. The Company acquired the contractual rights associated with the Separate Interests on July 29, 2011, and the

9

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2012

Company’s share of the net proceeds of $5,101,047 was received on August 23, 2011, which resulted in recognition of a gain in the third quarter of 2011 of $2,479,934. The Company applied the $5,101,047 of net proceeds to the payments due under the PSA.

The Company is in the process of evaluating the allocation of the purchase price to all assets and liabilities acquired. If the initial accounting for a business combination is incomplete by the end of the reporting period in which the combination occurs, the Company is required to report in its financial statements provisional amounts for the items for which the accounting is incomplete. During the measurement period, the Company shall retrospectively adjust the provisional amounts recognized at the acquisition date to reflect new information obtained about facts and circumstances that existed as of the acquisition date that, if known, would have affected the measurement of the amounts recognized as of that date.

During the measurement period, the Company is also required to recognize additional assets or liabilities if new information is obtained about facts and circumstances that existed as of the acquisition date that, if known, would have resulted in the recognition of those assets and liabilities as of that date. The measurement period ends as soon as the Company receives the information it was seeking about facts and circumstances that existed as of the acquisition date or learns that more information is not obtainable. However, the measurement period shall not exceed a year from the acquisition date.

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

	Quarter Ended June 30, 2011						Six Months Ended June 30, 2011:
	Historical			Pro Forma			Historical			Pro Forma
Total revenue	$	15,983		$	609,905		$	45,639		$	1,542,954
Net income (loss)	$	(840,394	)	$	(821,406	)	$	(1,294,073	)	$	(1,300,982	)
Net income (loss) applicable to common stockholders	$	(840,394	)	$	(821,406	)	$	(1,294,073	)	$	(1,300,982	)
Earnings per share:
Basic	$	(0.12	)	$	(0.12	)	$	(0.22	)	$	(0.22	)
Diluted	$	(0.12	)	$	(0.12	)	$	(0.22	)	$	(0.22	)

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 were recorded to eliminate gas gathering production costs payable to DNR that due to our purchase of the Buff field would have been eliminated, 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.

Property Disposition

In February 2012, the Company sold to an unaffiliated party a working interest in a well and related lease in Niobrara County, Wyoming for gross proceeds of approximately $1,109,000. After payment of additional consideration pursuant to the formula discussed under (b) in the acquisition table above, the Company realized net proceeds of $826,000. The purchaser assumed the asset retirement obligations estimated at approximately $16,000 and after deducting the net book value of the property, the Company recognized a gain on sale of $533,048. The Company retained a 2.575% overriding royalty interest in this property. This sale comprised

10

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2012

approximately 1.6% of the Company’s barrels of oil equivalent (“BOE”) of oil and gas reserve quantities, and approximately 2.2% of the Company’s discounted future net revenues prior to the sale. The Company determined that this sale did not qualify for discontinued operations reporting. All gains and losses recognized from oil and gas property sales are included in other operating revenues in the unaudited consolidated statements of operations.

4. Income Taxes

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

5. Stockholders’ Equity

Common Stock Issuances

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

	Number of Shares		Valuation Price		Amount
Board of Director fees:
Fees for second quarter of 2011		5,769	$	5.20	$	30,000
Fees for third quarter of 2011		10,000	$	3.00		30,000
Fees for fourth quarter of 2011		22,058	$	1.36		30,000
Fees for first quarter of 2012		27,778	$	1.08		30,000
Related party executive, administrative & operational services
Fees for January 2012		11,538	$	1.30		15,000
Fees for February 2012		12,500	$	1.20		15,000
Fees for March 2012		13,890	$	1.08		15,000
Fees for April 2012		13,044	$	1.15		15,000
Related party consulting services in June 2012		85,000	$	0.59		50,000
Accrued interest on unrelated party notes payable		7,750	$	1.35		10,462
Unrelated party consulting		6,000	$	1.08		6,480
Total		215,327	$	0.59	$	246,942

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

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

11

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2012

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

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

Preferred Stock Dividends

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

6. Contracts Payable

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

7. Notes and Advances Payable

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

	2011		2012
Officers, directors and affiliates:
Notes and advances payable, interest at 8.0%, due on demand	$	24,319	$	10,950
Notes and advances payable, interest at 9.7%, due on demand		85,000		85,000
Note payable, interest at 12.0%, due March 2013		—		150,000
Total officers, directors and affiliates		109,319		245,950
Unrelated parties:
Note payable, interest at 12.0%, due March 2013		—		250,000
Notes payable, interest at 12.0%, due March 2012		250,000		—
Total unrelated parties		250,000		250,000
Total notes and advance payable	$	359,319	$	495,950

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

12

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2012

8. Asset Retirement Obligations

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

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

Balance, December 31, 2011	$	653,240
Liabilities paid		—
Liabilities assumed by buyer of properties		(16,411	)
Accretion expense		4,101
Revisions of prior estimates		26,437
Balance, June 30, 2012		667,367
Less current asset retirement obligations		(67,527	)
Long-term asset retirement obligations	$	599,840

9. Related Party Operator Agreement

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

10. Subsequent events

In July 2012, the owner of the natural gas gathering system that the Company uses to transport production from its Colorado natural gas properties notified us that it is undertaking a program to significantly expand its gathering and processing capacity. While the long-term impact of this program may be somewhat favorable, the near term impact will likely be service interruptions and curtailments that could have an adverse impact on the Company’s future natural gas sales.

During April and June 2012, the Company received “force majeure” notices about service interruptions and curtailments that impacted the Colorado properties. Natural gas production for the Colorado properties was approximately 15% lower in the second quarter of 2012 compared to the first quarter of 2012.

13

Item 2 - Management’s Discussion and Analysis of Financial Condition and Results of Operations

Forward-looking information

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.

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 in our 2011 Annual Report on Form 10-K and the financial statements and footnotes included in this Quarterly Report on Form 10-Q. This Quarterly Report on Form 10-Q, 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 Quarterly Report on Form 10-Q 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:

• our lack of capital;

• possible write-downs in the financial statement carrying value of our properties;

• unsuccessful drilling and completion activities and the possibility of resulting write-downs;

• capital requirements and uncertainty of obtaining additional funding on terms of benefit to the Company;

• price volatility of oil and natural gas prices, and the effect that lower prices may have on our earnings and stockholders’ equity;

• a decline in oil or natural gas production or oil or natural gas prices, and the impact of general economic conditions on the demand for oil and natural gas and the availability of capital;

• geographical concentration of our operations;

• increases in the cost of drilling, completion and gas gathering or other costs of production and operations;

• our ability to successfully drill wells that produce oil or natural gas in commercially viable quantities;

• failure to meet our anticipated drilling activities;

• adverse variations from estimates of reserves, production, production prices and expenditure requirements, and our inability to replace our reserves through acquisition, exploration and development activities;

• our current high level of indebtedness and the effect of any increase in our level of indebtedness;

• limited control over non-operated properties;

• reliance on limited number of customers;

14

• title defects to our properties and inability to retain our leases;

• our ability to retain key members of our senior management and key consulting resources;

• federal, state and tribal regulations and laws;

• our working capital deficit;

• the impact of environmental, health and safety, and other governmental regulations, and of current or pending legislation;

• federal and state legislation and regulatory initiatives relating to hydraulic fracturing;

• risks in connection with evaluating potential acquisitions, integration of significant acquisitions, and difficulty managing our growth and the related demands on our resources;

• developments in the global economy;

• financing and interest rate exposure;

• effects of competition;

• effect of seasonal factors;

• lack of availability of drilling rigs, equipment, supplies, insurance, personnel and oil field services; and

• further sales or issuances of common stock.

Finally, our future results will depend upon various other risks and uncertainties, including, but not limited to, those detailed in the section entitled “Risk Factors” included in our 2011 Annual Report on Form 10-K. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements in this section and elsewhere in this report. Other than as required under securities laws, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise

General Overview

It is our desire to provide an understanding of the Company’s past performance, its financial condition and its prospects for the future. Accordingly, we will discuss and provide our analysis of the following:

• Critical accounting policies;

• Results of operations;

• Liquidity and capital resources;

• Contractual obligations

• New accounting pronouncements.

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

15

Critical Accounting Policies

The following discussion and analysis of the results of operations and financial condition are based on the our 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 the Notes to Consolidated Financial Statements included in our 2011 Annual Report on Form 10-K, as supplemented by the Unaudited Notes to Consolidated Financial Statements included herein. 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 of our control. 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 experience, our future business plans and projected financial results, the terms of existing contracts, our observance of trends in the oil and gas industry, information provided by our customers and information available from other outside sources, as appropriate. Actual results may differ from these estimates. We believe the following critical accounting policies affect our most significant judgments and estimates used in the preparation of our consolidated financial statements.

Revenue Recognition

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

Property and equipment

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.

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

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

16

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

We review our proved oil and gas properties and our gas gathering system for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the expected undiscounted future cash flows of assets evaluated for impairment and compare such undiscounted future cash flows to the carrying amount of the respective asset to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the asset 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 of oil equivalents (“BOE”) at the rate of six Mcf of natural gas to one barrel of oil. Estimated future dismantlement, restoration and abandonment costs, which are net of estimated salvage values, are taken into consideration.

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 using the units-of-production method on a field-by-field basis. The associated liability is classified in current and long-term liabilities in the consolidated balance sheets. The liability is periodically adjusted to reflect (1) new liabilities incurred, (2) liabilities settled during the period, (3) accretion expense and (4) revisions to estimated future cash flow requirements. The accretion expense is recorded as a component of depreciation, depletion and amortization expense in the consolidated statements of operations.

Stock-based Compensation

We have not granted any stock options or warrants during the six-months ended June 30, 2011 and 2012, and no options or warrants were outstanding at any time during 2011 and 2012. We issued shares of common stock for services performed by officers, directors and unrelated parties during 2011 and 2012, and we expect to issue shares for services in the future. We recorded these transactions based on the value of the services or the value of the common stock, whichever was more readily determinable.

17

Results of Operations for the Quarters Ended June 30, 2011 and 2012

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

Oil and Gas Producing Activities

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

Oil sales	$	410,689
Natural gas sales		70,671
Total revenue		481,360
Production taxes		(40,130	)
Lease operating expense		(117,944	)
Depreciation, depletion, amortization and accretion (“DD&A”)		(205,730	)
Net	$	117,556
Net barrels of oil sold		5,525
Net mcf of gas sold		20,457
Net Barrels of Oil Equivalent (“BOE”) sold		8,935
Average price per barrel of oil sold	$	74.33
Average price for per mcf of natural gas sold	$	3.45
Lease operating expense per BOE	$	13.20
DD&A per BOE	$	23.03

Our oil sales are primarily attributable to our properties in Kansas and Wyoming. The average oil price for the second quarter of 2012 of $74.33 per barrel decreased by 16.8% compared to $89.34 per barrel for the first quarter of 2012. Our average natural gas price, including proceeds from sales of natural gas liquids, amounted to $3.45 per Mcf for the second quarter of 2012 which is a decrease of 23.8% compared to $4.53 per Mcf for the first quarter of 2012. In July 2012, the owner of the natural gas gathering system that the Company uses to transport production from our Colorado natural gas properties notified us that it is undertaking a program to significantly expand its gathering and processing capacity. While the long-term impact of this program may be somewhat favorable, the near term impact will likely be service interruptions and curtailments that could have an adverse impact on our future natural gas sales.

During April and June 2012, the Company received “force majeure” notices about service interruptions and curtailments. Natural gas production for our Colorado properties was approximately 15% lower in the second quarter of 2012 compared to the first quarter of 2012.

Production taxes were approximately 8.3% of our oil and gas sales for the second quarter of 2012. Lease operating expense averaged $13.20 per BOE for the second quarter for 2012. Many of the wells included in our acquisition have been producing for more than a decade and consequently repairs and oilfield services are needed to maintain production levels. For the second quarter of 2012, we incurred approximately $10,000 for well services and repairs, which accounted for approximately $1.16 per BOE of our lease operating expenses for the second quarter of 2012.

18

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. For the second quarter of 2012, our DD&A per BOE was $23.03. During the second quarter of 2012, we revised our estimates for plugging and abandonment costs and reduced our estimates of proved reserves for certain wells that we intend to plug and abandon. The aggregate impact of these changes resulted in an increase in DD&A expense of approximately $74,000 for the second quarter of 2012.

Gas Gathering Activities

We have owned and operated a natural gas gathering system (pipeline and compressor station) for coal bed methane properties in the Powder River Basin of Wyoming since 2006. We had $15,983 of revenues for the second quarter of 2011 compared to no revenues for the second quarter of 2012. Due to a reduction in natural gas prices, all wells in the field have been shut-in since June 2011.

Presented below is a summary of operating costs for the gas gathering system for the quarters ended June 30, 2011 and 2012:

	2011		2012		Percent Change
Related party- cost of production	$	10,204	$	—		(100.0	%)
Unrelated parties:
Compressor rental		18,785		—		(100.0	%)
Pumper costs		7,500		—		(100.0	%)
Transportation		1,375		—		(100.0	%)
Property taxes		1,618		1,393		(13.9	%)
Land rent, utilities, repairs and other		4,137		2,267		(45.2	%)
Total unrelated party costs		33,415		3,660		(89.0	%)
Total	$	43,619	$	3,660		(91.6	%)

The reductions in related party cost of production, and unrelated party expenses for compressor rental, pumper costs and transportation during 2012 were primarily due to the decision to shut-in the coal bed methane properties in June 2011 which allowed us to substantially eliminate these costs for the remainder of 2011 and the second quarter of 2012. Depreciation expense related to the gas gathering system was $11,055 for the second quarter of both 2011 and 2012.

19

General and Administrative

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

	2011		2012		Change
Director fees	$	30,000	$	30,000	$	—
Investor relations		84,782		84,227		(555	)
Acquisition investigation and due diligence		472,978		—		(472,978	)
Legal, auditing and transfer agent		42,430		28,562		(13,868	)
Consulting and executive services:
Related parties		56,375		155,750		99,375
Unrelated parties		83,610		55,059		(28,551	)
Other administrative services		8,970		29,249		20,279
Depreciation		—		142		142
Total general and administrative expenses	$	779,145	$	382,989	$	(396,156	)

General and administrative expenses decreased by $396,156 in 2012 compared to 2011, primarily due to decreases in acquisition investigation and due diligence costs of $472,978 and unrelated party consulting fees of $28,551. These decreases were offset by increases in consulting and executive services with related parties of $99,375 and other administrative services of $20,279.

The decrease in acquisition investigation and due diligence costs of $472,978 was primarily due to a charge of $457,500 under a consulting agreement entered into during the second quarter of 2011 to evaluate the oil and gas properties that were ultimately acquired in the third quarter of 2011. We did not evaluate any significant acquisitions during the second quarter of 2012 and, accordingly, no costs were incurred. The decrease in consulting fees paid to unrelated parties of $28,551 was primarily attributable to a reduction in consulting fees related to capital structure and financings in the second quarter of 2012. The increase in other administrative expenses of $20,279 was primarily due to new insurance coverage for officer and director liability and higher travel costs in 2012. The increase in consulting and executive services with related parties of $99,375 was primarily due to the following:

• Effective October 1, 2011, the Company entered into an Operator Agreement with DNR which results in a quarterly charge of $45,000 to provide executive level operations expertise for our existing and prospective oil and properties. The total quarterly charge under the operating agreement is $69,000, of which $24,000 is allocated to lease operating expense and $45,000 is allocated to general and administrative expenses. DNR is an affiliate of Charles B. Davis, an executive officer and director of the Company.

• Effective January 1, 2012, the Board of Directors agreed to pay fees for executive, administrative and operational services in the aggregate amount of $15,000 per month to three individuals who are directors and/or stockholders of the Company. These fees are payable in shares of the Company’s common stock based on the closing price on the last day of the month for which the services are performed. For the quarter ended June 30, 2012, the Company incurred aggregate fees of $45,000 under this arrangement.

Loss from operations

Loss from operations for the second quarter of 2012 was $280,148 compared to a loss of $817,836 for the second quarter of 2011. The improvement of approximately $537,688 was primarily due to the elimination of approximately $472,978 of fees for acquisition investigation and due diligence in the second quarter of 2012, as well as the other items discussed above relating to the oil and natural gas operations, gas gathering activities, and general and administrative expenses.

20

Interest Expense

Interest expense decreased from $22,697 for the second quarter of 2011 to $14,556 for the second quarter of 2012, a decrease of $8,141. This decrease was primarily due to a reduction in weighted average borrowing during the second quarter of 2012.

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

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

Oil and Gas Producing Activities

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

Oil sales	$	861,319
Natural gas sales		174,076
Total Revenue		1,035,395
Production taxes		(84,326	)
Lease operating expense		(401,653	)
Depreciation, depletion, amortization and accretion (“DD&A)		(336,837	)
Net	$	212,579
Net barrels of oil sold		10,565
Net mcf of gas sold		43,320
Net Barrels of Oil Equivalent (“BOE”) sold		17,785
Average price for oil	$	81.53
Average price for gas	$	4.02
Lease operating expense per BOE	$	22.58
DD&A per BOE	$	18.94

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

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

21

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

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

Gas Gathering Activities

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

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

	2011		2012		Percent Change
Related party- cost of production	$	30,815	$	—		(100.0	%)
Unrelated parties:
Compressor rental		46,961		—		(100.0	%)
Pumper costs		15,000		—		(100.0	%)
Transportation		8,042		—		(100.0	%)
Property taxes		3,236		2,785		(13.9	%)
Land rent, utilities, repairs and other		7,319		4,535		(38.0	%)
Total unrelated party costs		80,558		7,320		(90.9	%)
Total	$	111,373	$	7,320		(93.4	%)

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

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

22

General and Administrative

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

	2011		2012		Change
Director fees	$	60,000	$	60,000	$	—
Investor relations		225,322		130,031		(95,291	)
Acquisition investigation and due diligence		500,478		—		(500,478	)
Legal, auditing and transfer agent		85,969		77,642		(8,327	)
Consulting and executive services:
Related parties		112,750		316,500		203,750
Unrelated parties		161,852		76,504		(85,348	)
Other administrative expenses		25,695		42,795		17,100
Depreciation		—		285		285
Total general and administrative expenses	$	1,172,066	$	703,757	$	(468,309	)

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

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

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

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

23

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

Income (loss) from operations

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

Interest Expense

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

Liquidity and Capital Resources

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

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

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

24

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

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

We are currently in preliminary discussions with lenders that have expressed an interest in providing a line of credit that would be secured by our oil and gas properties. There is no assurance that we will be successful in attracting a lender or that the amount of any financing will be sufficient to execute our business plan for 2012.

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

Contractual Obligations and Commercial Commitments

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

Off-Balance Sheet Arrangements

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

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

25

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

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

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

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

New Accounting Pronouncements

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

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

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

26

Item 3 - Quantitative and Qualitative Disclosures about Market Risk

The Company is a “Smaller Reporting Company” as defined by Rule 229.10 (f)(1) and is not required to provide or disclose the information required by this item.

Item 4 - Controls and Procedures

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

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

27

PART II - OTHER INFORMATION

Item 1 - Legal Proceedings.

From time to time, the Company is a party to routine litigation and proceedings that are considered part of the ordinary course of its business. The Company is not aware of any material current, pending, or threatened litigation.

Item 1A - Risk Factors.

There have been no material changes to the risk factors set forth in our Annual Report on Form 10-K for the year ended December 31, 2011, as filed with the SEC on April 16, 2012 and amended on May 1, 2012. The risk factors in our Annual Report on Form 10-K for the year ended December 31, 2011, in addition to the other information set forth in this quarterly report, could materially affect our business, financial condition or results of operations. Additional risks and uncertainties not currently known to us or that we deem to be immaterial could also materially adversely affect our business, financial condition or results of operations.

Item 2 - Unregistered Sales of Equity Securities and Use of Proceeds.

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

	Number of Shares		Valuation Price		Amount
Board of Director fees:
Fees for second quarter of 2011		5,769	$	5.20	$	30,000
Fees for third quarter of 2011		10,000	$	3.00		30,000
Fees for fourth quarter of 2011		22,058	$	1.36		30,000
Fees for first quarter of 2012		27,778	$	1.08		30,000
Related party executive, administrative & operational services
Fees for January 2012		11,538	$	1.30		15,000
Fees for February 2012		12,500	$	1.20		15,000
Fees for March 2012		13,890	$	1.08		15,000
Fees for April 2012		13,044	$	1.15		15,000
Related party consulting services in June 2012		85,000	$	0.59		50,000
Accrued interest on unrelated party notes payable		7,750	$	1.35		10,462
Unrelated party consulting		6,000	$	1.08		6,480
Total		215,327	$	0.59	$	246,942

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

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

28

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

In issuing the shares of common stock to these persons, the Company relied upon the exemption from registration provided by Section 4(2) of the Securities Act of 1933. Each of the investors purchasing the securities made representations to the Company concerning their investment sophistication and knowledge of the Company’s business operations and financial condition.

Item 3 - Defaults upon Senior Securities.

None

Item 4 - Mine Safety Disclosures.

Not Applicable

Item 5 - Other Information.

None

Item 6 - Exhibits

The following documents are filed as exhibits to this report on Form 10-Q or incorporated by reference herein.

31.1 Certification of the Principal Executive Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.

31.2 Certification of the Principal Financial Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.

32.1 Certification of the Principal Executive Officer pursuant to 18 U.S.C. Section 1350.

32.2 Certification of the Principal Financial Officer pursuant to 18 U.S.C. Section 1350.

29

ARÊTE INDUSTRIES, INC.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

By:	/s/ Donald W. Prosser, CEO
Donald W. Prosser, Principal Executive Officer
Dated: August 15, 2012
By:	/s/ John Herzog, Interim CFO
John Herzog, Interim Principal Financial and Accounting Officer
Dated: August 15, 2012

30

EX-31.1

Exhibit 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Donald W. Prosser, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Arête Industries, Inc.

2. Based on my knowledge, this quarterly 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 quarterly report;

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

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) 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 registrant, including any consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

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

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

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

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’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 registrant’s ability to record, process, summarize and report financial information; and

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

Dated: August 15, 2012	By:	/s/ Donald W. Prosser
		Donald W. Prosser, Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION OF PRINCIPAL ACCOUNTING OFFICER

PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, John Herzog, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Arête Industries, Inc.

2. Based on my knowledge, this quarterly 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 quarterly report;

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

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

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

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

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

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

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’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 registrant’s ability to record, process, summarize and report financial information; and

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

Dated: August 15, 2012	By:	/s/ John Herzog
		John Herzog, Interim Chief Financial Officer

EX-32.1

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 Quarterly Report of Arête Industries, Inc. (the “Company”) on Form 10-Q for the period ending June 30, 2012, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), 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; and

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

Dated: August 15, 2012	By:	/s/ Donald W. Prosser
		Donald W. Prosser, Chief Executive Officer

EX-32.2

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 Quarterly Report of Arête Industries, Inc. (the “Company”) on Form 10-Q for the period ending June 30, 2012, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, John Herzog, Interim 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; and

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

Dated: August 15, 2012	By:	/s/ John Herzog
		John Herzog, Interim Chief Financial Officer