Arête Industries 10Q 2013 Q2 Quarterly report

Arête Industries (ARET) Inactive 10-Q2013 Q2 Quarterly report

Content analysis

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

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, 2013

¨	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.)

7260 Osceola Street, Westminster, Colorado		80030
(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. x Yes ¨ 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.

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 5, 2013, the Registrant had 13,251,466 shares of common stock issued and outstanding.

ARÊTE INDUSTRIES, INC.

Table of Contents


	Page
Part 1—Financial Information
Item 1—Financial Statements		3
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 2—Unregistered Sales of Equity Securities and Use of Proceeds		28
Item 3—Defaults upon Senior Securities		28
Item 4—Mine Safety Disclosures		28
Item 5—Other Information		28
Item 6 – Exhibits		28
Signatures		29

Part 1 – FINANCIAL INFORMATION

Item 1—Financial Statements

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED BALANCE SHEETS

December 31, 2012 and June 30, 2013


	2012			2013
ASSETS
Current Assets:
Cash and equivalents	$	6,921		$	418
Receivable from DNR Oil & Gas, Inc.:
Oil and gas sales, net of production costs		87,989			229,010
Other		61,243			72,721
Prepaid expenses and other		61,034			24,417

Total Current Assets		217,187			326,566

Property and Equipment:
Oil and gas properties, at cost, successful efforts method:
Proved properties		9,389,245			9,578,355
Unevaluated properties		314,336			314,336
Natural gas gathering system		442,195			442,195
Furniture and equipment		22,522			22,522

Total property and equipment		10,168,298			10,357,408
Less accumulated depreciation, depletion and amortization		(1,499,284	)		(1,811,954	)

Net Property and Equipment		8,669,014			8,545,454

TOTAL ASSETS	$	8,886,201		$	8,872,020

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED BALANCE SHEETS

December 31, 2012 and June 30, 2013


	2012			2013
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable:
Payable to DNR Oil & Gas, Inc.:
Oil and gas property acquisition costs	$	250,000		$	250,000
Gas gathering operating costs		436,403			436,403
Operator fees and other		159,748			159,748
Unrelated parties		92,943			74,184
Notes and advances payable—current portion
Directors and affiliates		508,991			1,049,794
Unrelated parties		250,000			—
Accrued interest expense		48,359			49,114
Director fees payable in common stock		33,615			34,965
Accrued consulting services payable in common stock		42,000			42,000
Current portion of asset retirement obligations		78,140			111,315
Other accrued costs and expenses		255,740			92,492

Total Current Liabilities		2,155,939			2,300,015

Long-Term Liabilities:
Contingent acquisition costs payable to DNR Oil & Gas, Inc.		250,000			250,000
Notes and advances payable, net of current portion
Directors and affiliates		—			150,000
Unrelated parties		—			850,000
Asset retirement obligations, net of current portion		569,128			569,013

Total Long-Term Liabilities		819,128			1,819,013

Total Liabilities		2,975,067			4,119,028

Commitments and Contingencies (Notes 3, 4, and 10)
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 2012 and 25 shares in 2013, liquidation preference of $5,420,938 in 2012 and $259,375 in 2013		4,987,326			238,628
Series 2; authorized 2,500 shares, no shares issued and outstanding in 2012 and 2013		—			—
Common stock, no par value; authorized 499,000,000 shares, issued and outstanding 7,979,801 in 2012 and 13,251,466 in 2013		17,151,097			21,267,795
Accumulated deficit		(16,227,289	)		(16,753,431	)

Total Stockholders’ Equity		5,911,134			4,752,992

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	8,886,201		$	8,872,020

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

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS

For the Quarters and the Six Months Ended June 30, 2012 and 2013


	Quarter Ended June 30:						Six-Months Ended June 30
	2012			2013			2012			2013
Revenues:
Oil and natural gas sales	$	481,360		$	516,267		$	1,035,395		$	973,992
Sale of oil and natural gas properties		—			—			533,048			949

Total revenues		481,360			516,267			1,568,443			974,941

Operating Expenses:
Oil and gas producing activities:
Lease operating expenses		117,944			153,593			401,653			341,400
Production taxes		40,130			41,028			84,326			76,865
Depreciation, depletion, amortization and accretion		205,730			150,733			336,837			323,335
Gas gathering:
Operating expenses		3,660			4,142			7,320			7,685
Depreciation		11,055			11,055			22,110			22,110
General and administrative expenses:
Director fees		30,000			900			60,000			1,350
Investor relations		84,227			44,530			130,031			75,427
Legal, auditing and professional services		28,562			66,300			77,642			96,890
Consulting and executive services:
Related parties		155,750			30,750			316,500			61,500
Unrelated parties		55,059			—			76,504			—
Other administrative expenses		29,249			19,192			42,795			40,562
Depreciation		142			—			285			285

Total operating expenses		761,508			522,223			1,556,003			1,047,409

Operating income (loss)		(280,148	)		(5,956	)		12,440			(72,468	)
Other income (expense):
Interest income		65			—			220			1
Interest expense		(14,556	)		(36,304	)		(32,401	)		(61,800	)

Loss before income taxes		(294,639	)		(42,260	)		(19,741	)		(134,267	)
Income tax benefit (expense)		—			—			—			—

Net loss	$	(294,639	)	$	(42,260	)	$	(19,741	)	$	(134,267	)

Net Loss Applicable to Common Stockholders:
Net loss	$	(294,639	)	$	(42,260	)	$	(19,741	)	$	(134,267	)
Redemption of preferred stock		—			3,053,365			—			3,053,365
Accrued preferred stock dividends		(195,938	)		(9,375	)		(391,875	)		(205,313	)

Net loss applicable to common stockholders	$	(490,577	)	$	3,001,730		$	(411,616	)	$	2,713,785

Earnings (Loss) Per Share Applicable to Common Stockholders:
Basic	$	(0.06	)	$	0.37		$	(0.05	)	$	0.34

Diluted	$	(0.06	)	$	0.23		$	(0.05	)	$	0.20

Weighted Average Number of Common Shares Outstanding:
Basic		7,788,000			8,125,000			7,776,000			8,055,000

Diluted		7,788,000			13,251,466			7,776,000			13,251,466

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

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

Quarter Ended June 30, 2013


	Class A Preferred Stock						Common Stock				Accumulated Deficit			Total
	Shares			Amount			Shares		Amount		Accumulated Deficit			Total
Balances, December 31, 2012		522.5		$	4,987,326			7,979,801	$	17,151,097	$	(16,227,289	)	$	5,911,134
Issuance of common stock for fees								45,000		18,000					18,000
Conversation of Series A
Preferred Stock		(497.5	)		(4,748,698	)		5,226,665		4,098,698				$	(650,000	)
Preferred dividends paid												(391,875	)		(391,875	)
Net loss		—			—			—		—		(134,267	)		(134,267	)

Balances, June 30, 2013		25.0		$	238,628			13,251,466	$	21,267,795	$	(16,753,431	)	$	4,752,992

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

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS

Quarters Ended June 30, 2012 and 2013


	2012			2013
Cash Flows from Operating Activities:
Net income (loss)	$	(19,741	)	$	(134,267	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		355,132			312,670
Accretion of discount on asset retirement obligations		4,100			33,060
Gain on sale of oil and gas properties		(533,048	)		(949	)
Common stock issued in exchage for services		246,942			18,000
Common stock issued in exchage for accrued interest		10,462			—
Changes in operating assets and liabilities:
Accounts receivable		(76,179	)		(152,499	)
Prepaid expenses and other		60,714			36,617
Accounts payable		24,461			(18,758	)
Accrued costs and expenses		2,590			(161,141	)

Net cash provided by (used in) operating activities		75,433			(67,267	)

Cash Flows from Investing Activities:
Capital expenditures for property and equipment		(646,269	)		(189,110	)
Proceeds from sale of oil and gas properties		1,108,709			949
Contingent consideration paid to DNR under sharing arrangement		(282,704	)		—

Net cash provided by (used in) investing activities		179,736			(188,161	)

Cash Flows from Financing Activities:
Proceeds from notes and advance payable		400,000			1,040,935
Principal payments on notes payable		(264,619	)		(350,135	)
Payment of dividends on preferred stock		(391,875	)		(391,875	)
Redemption of preferred stock		—			(50,000	)
Payment of preferred stock offering costs		(50,000	)		—

Net cash provided by (used in) financing activities		(306,494	)		248,925

Net decrease in cash and equivalents		(51,325	)		(6,503	)
Cash and equivalents, beginning of period		219,566			6,921

Cash and equivalents, end of period	$	168,241		$	418

Supplemental Disclosure of Cash Flow Information:
Cash paid for interest	$	83,827		$	51,045

Cash paid for income taxes	$	—		$	—

Supplemental Disclosure of Non-cash Investing and Financing Activities:
Payable to DNR for acquisition of oil and gas properties	$	291,616		$	—

Asset retirement obligations assumed upon sale 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.

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2013

1. Organization and Nature of Operations

Arête Industries, Inc. (“Arête” or the “Company”), is a Colorado corporation that was incorporated on July 21, 1987. The Company owns 100% of Arete Energy, Inc. which is an inactive subsidiary which has no assets, liabilities or operations. Arête has operated a natural gas gathering system in Wyoming since 2006 and on July 29, 2011 the Company purchased oil & natural gas properties in Colorado, Montana, Kansas, and Wyoming.

The Company seeks to focus on acquiring interests in traditional oil and gas ventures, and seek 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 the sale and farm out of 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, 2012 and June 30, 2013, and the results of operations, changes in stockholders’ equity, and cash flows for the six months and quarters ended June 30, 2012 and 2013. 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 2012 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 2012 Annual Report on Form 10-K.

Use of Estimates

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

The most significant areas requiring the use of assumptions, judgments and estimates relate to the volumes of natural gas and oil reserves used in calculating depreciation, depletion and amortization (“DD&A”), the amount of expected future cash flows used in determining possible impairments of oil and gas properties and the amount of future capital costs used in these calculations. Assumptions, judgments and estimates also are required in determining future asset retirement obligations, impairments of undeveloped properties, and in valuing stock-based payment awards.

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.

Principles of Consolidation

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

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.

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2013

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, 2013, the convertible preferred stock had an aggregate liquidation preference of $259,375 and was convertible to 75,758 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 February 2013, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2013-02,Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income, to improve the transparency of reporting these reclassifications. Other comprehensive income includes gains and losses that are initially excluded from net income for an accounting period. Those gains and losses are later reclassified out of accumulated other comprehensive income into net income. The amendments in the ASU do not change the current requirements for reporting net income or other comprehensive income in financial statements. All of the information that this ASU requires already is required to be disclosed elsewhere in the financial statements under U.S. GAAP. The new amendments will require an organization to:

•

Present (either on the face of the statement where net income is presented or in the notes) the effects on the line items of net income of significant amounts reclassified out of accumulated other comprehensive income—but only if the item reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period; and

•

Cross-reference to other disclosures currently required under U.S. GAAP for other reclassification items (that are not required under U.S. GAAP) to be reclassified directly to net income in their entirety in the same reporting period. This would be the case when a portion of the amount reclassified out of accumulated other comprehensive income is initially transferred to a balance sheet account (e.g., inventory for pension-related amounts) instead of directly to income or expense.

The amendments apply to all public and private companies that report items of other comprehensive income. Public companies are required to comply with these amendments for all reporting periods (interim and annual). The amendments are effective for reporting periods beginning after December 15, 2012, for public companies. Early adoption is permitted. The adoption of ASU No. 2013-02 is not expected to have a material impact on our financial position or results of operations.

In January 2013, the FASB issued ASU No. 2013-01,Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, which clarifies which instruments and transactions are subject to the offsetting disclosure requirements originally established by ASU 2011-11. The new ASU addresses preparer concerns that the scope of the disclosure requirements under ASU 2011-11 was overly broad and imposed unintended costs that were not commensurate with estimated benefits to financial statement users. In choosing to narrow the scope of the offsetting disclosures, the Board determined that it could make them more operable and cost effective for preparers while still giving financial statement users sufficient information to analyze the most significant presentation differences between financial statements prepared in accordance with U.S. GAAP. Like ASU 2011-11, the amendments in this update will be effective for fiscal periods beginning on, or after January 1, 2013. The adoption of ASU 2013-01 is not expected to have a material impact on our financial position or results of operations.

In October 2012, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2012-04, “Technical Corrections and Improvements” in Accounting Standards Update No. 2012-04. The amendments in this update cover a wide range of Topics in the Accounting Standards Codification. These amendments include technical corrections and improvements to the Accounting Standards Codification and conforming amendments related to fair value measurements. The amendments in this update will be effective for fiscal periods beginning after December 15, 2012. The adoption of ASU 2012-04 is not expected to have a material impact on our financial position or results of operations.

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2013

In August 2012, the FASB issued ASU 2012-03, “Technical Amendments and Corrections to SEC Sections: Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin (SAB) No. 114, Technical Amendments Pursuant to SEC Release No. 33-9250, and Corrections Related to FASB Accounting Standards Update 2010-22 (SEC Update)” in Accounting Standards Update No. 2012-03. This update amends various SEC paragraphs pursuant to the issuance of SAB No. 114. The adoption of ASU 2012-03 is not expected to have a material impact on our financial position or results of operations.

In July 2012, the FASB issued ASU 2012-02, “Intangibles – Goodwill and Other (Topic 350): Testing Indefinite-Lived Intangible Assets for Impairment” in Accounting Standards Update No. 2012-02. This update amends ASU 2011-08, Intangibles – Goodwill and Other (Topic 350): Testing Indefinite-Lived Intangible Assets for Impairment and permits an entity first to assess qualitative factors to determine whether it is more likely than not that an indefinite-lived intangible asset is impaired as a basis for determining whether it is necessary to perform the quantitative impairment test in accordance with Subtopic 350-30, Intangibles—Goodwill and Other—General Intangibles Other than Goodwill. The amendments are effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012. Early adoption is permitted, including for annual and interim impairment tests performed as of a date before July 27, 2012, if a public entity’s financial statements for the most recent annual or interim period have not yet been issued or, for nonpublic entities, have not yet been made available for issuance. The adoption of ASU 2012-02 is not expected to have a material impact on our financial position or results of operations.

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.

3. Disposition of Oil and Gas Properties

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 in the additional consideration agreement in the Amended and Restated Purchase and Sale Agreement dated July 29, 2011, the Company realized net proceeds of $826,000. The purchaser assumed the asset retirement obligations estimated at approximately $16,000 and after deducting the net book value of the property, the Company recognized a gain on sale of $533,048. The Company retained a 2.575% overriding royalty interest in this property. This sale comprised approximately 1.6% of the Company’s barrels of oil equivalent (“BOE”) of oil and gas reserve quantities, and approximately 2.2% of the Company’s discounted future net revenues prior to the sale. The Company determined that this sale did not qualify for discontinued operations reporting.

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 $8.4 million which expire in 2018 through 2032. 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. For the quarter ended June 30, 2013, the Company did not recognize any income tax benefit due to the valuation allowance.

5. Stock transactions and preferred stock dividends

During the six months ended June 30, 2013, the Company issued 45,000 shares of common stock for payment of fees accrued to a consultant. The Board of Directors has declared the semi-annual dividend payable to preferred shareholders of record as of March 31, 2013. The Board of Directors declared the preferred dividend of $391,875 on April 26, 2013 and paid the dividend in cash on April 28, 2013.

Effective June 28, 2013, several holders of the Company’s 15% Series A1 Convertible Preferred Stock (“Series A1 Preferred Stock”) elected to convert shares of such stock into the Company’s common stock at a redemption price of $0.75 per common share. In connection with those predemptions all such holders agreed to waive all dividend rights on their shares of Series A1 Preferred Stock subsequent to March 30, 2013. Information regarding the conversions is set forth below.

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2013


Name of Holder	Number of Shares of Series A1 Preferred Stock Converted	Number of Common Shares Issued
Burlingame Equity Investors II, LP	16	100,800
Burlingame Equity Investors Master Fund, LP	184	1,159,200
Charles B. Davis*	100	1,333,333
Tucker Family Investments LLLP	25	333,333
Mark Venjohn	10	133,333
Pete Haman	35	466,667
Nicholas L. Scheidt*	100	1,333,333
Michael J. Finney	5	66,667
William and Sara Kroske	2.5	33,333
Michael A. Geller	10	133,333
John H. Rosasco	10	133,333

*	Executive Officer and Director of the Company

In addition, in connection with the conversions of Series A1 Preferred Stock by Burlingame Equity Investors II, LP and Burlingame Equity Investors Master Fund, LP, the Company also entered into transactions with such entities in exchange for cash consideration, promissory notes and cancellation of certain Series A1 Preferred Shares.


Name of Holder	Cash Consideration		Promissory Note – Principal		Series A1 Preferred Shares Cancelled
Burlingame Equity Investors II, LP	$	4,000	$	48,000		16
Burlingame Equity Investors Master Fund, LP	$	46,000	$	552,000		184

The above promissory notes bear interest at 7% per annum, with interest payable quarterly and all unpaid interest and principal due on July 23, 2014. If the promissory notes are not paid when due or declared due, the entire principal and interest thereon will bear interest at the rate of 12% per annum.

The redemption of preferred stock on the earning per share applicable to common stockholders was calculated as the difference between the fair market value of common shares received on June 28, 2013 and the cost of the preferred stock redeemed.

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 was for a period of three years and the fair value of the services were amortized ratably over the service period. Accordingly, the Company recognized a charge to investor relations expense of $83,333 and $27,778 for the six months ended June 30, 2012 and 2013, respectively.

7. Notes and advances payable

Notes payable consist of the following as of December 31, 2012 and June 30, 2013:


	2012		2013
Officers, directors and affiliates:
Notes and advances payable, interest at 8.0%, due on demand	$	12,882	$	13,249
Notes and advances payable, interest at 9.7%, due on demand		85,000		85,000
Note payable, interest at 7.5%, due March 2015		150,000		150,000
Collateralized note payable (see below)		261,109		951,545

Total officers, directors, and affiliates		508,991		1,199,794
Less: Current portion of officers, directors, and affiliates		508,991		1,049,794

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2013


Long-term portion of officers, directors, and affiliates	$	—	$	150,000

Unrelated parties:
Notes payable, interest at 7.5%, due March 2015		250,000		250,000
Notes payable, interest at 7.0%, due July 2014 (see note 5)		—		48,000
Notes payable, interest at 7.0%, due July 2014 (see note 5)		—		552,000

Total unrelated parties		250,000		850,000
Less: Current portion of unrelated parties		250,000		—

Long-term portion of unrelated parties	$	—	$	850,000

On September 29, 2012, the Company borrowed $425,000 from an affiliate of a stockholder and director under a note agreement that provides for interest at the stated annual rate of 12% (and an effective annual rate of 17.8%) with unpaid principal and interest due on March 29, 2013. The outstanding principal balance as of March 31, 2013 was $261,109 and was paid in full April 29, 2013.

On April 29, 2013, the Company executed a promissory note under which the Company agreed to pay Apex Financial Services Corp, a Colorado corporation, (“Apex”) the principal sum of $1,000,000, with interest accruing at an annual rate of 7.5%, with principal and interest due on May 31, 2014. The Company also agreed to assign 75% of its operating income from its oil and gas operations and any lease or well sale or any other assets sales to Apex to secure the debt. Apex is 100% owned by the CEO, director, and shareholder of the Company, Nicholas L. Scheidt. The Company borrowed the full amount of principal on the note, and also paid a loan fee of $10,000. In the event of default on the note and failure to cure the default in ten days, Apex may accelerate payment and the annual interest rate on the note will accrue at 18%. Default includes failure to pay the note when due or if the Company borrows any other monies or offers security in the Company or in the collateral securing the note prior to the note being paid in full.

All of the notes payable shown above are unsecured, except the Apex note. Accrued interest on notes and advances payable amounted to $48,359 as of December 31, 2012 and $49,114 as of June 30, 2013.

8. Asset retirement obligations (ARO)

A reconciliation of the Company’s asset retirement obligations for the quarter ended June 30, 2013, is as follows:


Balance, December 31, 2012	$	647,268
Liabilities incurred		—
Accretion expense		33,060
Revisions to estimate		—

Balance, June 30, 2013		680,328
Less current asset retirement obligations		(111,315	)

Long-term asset retirement obligations	$	569,013

9. Related Party Cost Reductions

In connection with the property 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 Consolidated Statements of Operations for the first quarter of 2012. Effective July 1, 2012, the monthly operator fee was reduced to $18,000 per month, of which $8,000 per month is included in lease operating expense and the remaining $10,000 per month is included in related party consulting fees.

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2013

Effective July 1, 2012 the Company reduced the amount paid for director fees and other related party consulting arrangements. Presented below is a comparison of the impact of related party cost reductions for the first two quarters of 2012 compared to the first two quarters of 2013:


	Six Months Ended:
	6/30/12		6/30/13		Reduction
Fees payable in cash:
Operator fees	$	138,000	$	108,000	$	30,000
Consulting fees		30,000		—		30,000
Fees payable in shares of common stock:

Director fees		60,000		1,350		58,650
Consulting fees		90,000		—		90,000

	$	318,000	$	109,350	$	208,650

If these cost reductions had not been implemented for the first two quarters of 2013, the Company’s net income applicable to common stockholders would have decreased from $2,713,785 to $2,505,135, and net income per share applicable to common stockholders would have decreased from $0.34 to $0.31.

10. Subsequent events

During the first quarter 2013 the Company drilled a well in Kansas in which it has a 20% working interest and has $134,261 of costs as of June 30, 2013. The costs are carried as part of proved properties on the balance sheet as a well in progress. The Company has information as to the results of the well as of August 5, 2013. The results are being evaluated by the 50% working interest owner for a decision on the completion of the well and it’s economics.

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 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:

•

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

•

our substantial capital requirements and uncertainty of obtaining additional funding on terms acceptable to us;

•

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;

•

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 level of significant indebtedness and the effect of any increase in our level of indebtedness;

•

limited control over non-operated properties;

•

reliance on limited number of customers;

•

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;

•

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 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 drilling opportunities. While we have made progress to implement our business strategy over the past year, we believe our primary challenge for the foreseeable future is to obtain additional financing to be able 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 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 significant 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.

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 Annual Report on Form 10-K for the year ended December 31, 2012, 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, 2013 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.

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

Stock-based Compensation

We have not granted any stock options or warrants during the six months ended June 30, 2012 and 2013, and no options or warrants were outstanding at any time during 2012 and 2013. We issued shares of common stock for services performed by officers, directors and unrelated parties during 2013 and we expect to issue 45,000 shares for fees. We recorded these transactions based on the value of the services or the value of the common stock, whichever was more readily determinable.

Results of Operations for the Quarters Ended June 30, 2012 and 2013

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, 2012 and 2013.

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. Presented below is a summary of our oil and gas operations for the quarters ended June 30, 2012 and 2013:


	2012			2013
Oil Sales	$	410,689		$	398,084
Natural Gas Sales		70,671			118,183

Total Revenue		481,360			516,267

Production Taxes		(40,130	)		(41,028	)
Lease Operating Expense		(117,944	)		(153,593	)
Depreciation, depletion, amortization and accretion		(205,730	)		(150,733	)

Net	$	117,556		$	170,913

Net barrels of oil sold		5,525			4,991
Net mcf of gas sold		20,457			21,785
Average price for oil (bbl)	$	74.33		$	79.76

Average price for gas (mcf)	$	3.45		$	5.43

Lease operating expense per BOE	$	13.20		$	17.81

DD&A per BOE	$	23.03		$	17.48

Our oil sales are primarily attributable to our properties in Kansas and Wyoming. The average oil price for the second quarter of 2013 was $79.76 per barrel but ranged from a low of $77.79 for May and a high of $83.94 for June. The average oil price for the second quarter of 2012 was $74.33 per barrel but ranged from a low of $69.94 for April to a high of $76.85 for June. The oil revenue for the second quarter 2013 was down compared to the same quarter 2012. Although we received a higher average oil price for the 2013 second quarter of $5.43 per barrel we sold 257 barrels less then we produced or $20,498 at our average price per barrel. The average natural gas prices, including proceeds from sales of natural gas liquids, amounted to $5.43 per Mcf for the second quarter of 2013 which was an increase $1.98 per Mcf and an increase of 36% for the quarter. We were under a “force majeure” notice causing service interruptions and curtailments for our Colorado properties during the second quarter of 2012. Therefore the increase in natural gas sales during the second quarter of 2013 was due the removal of the “force majeure” notice.

Production taxes were approximately 8% of our oil and gas sales for the second quarters of 2013 and 2012. Lease operating expense averaged $17.81 per BOE, whereby six Mcf of gas are equal to one barrel of oil, for the second quarter of 2013. Lease operating expense averaged $13.20 per BOE for the same period 2012. Many of the wells included in our 2011 acquisition have been producing for a decade or longer and the cost of workovers and normal maintenance are charged to expense in the period the costs are incurred. For the second quarter of 2013, we incurred approximately $8,000 for workovers, well service units and repairs which accounted for approximately $0.96 per BOE of our lease operating expenses that was capitalized based on increased production the wells. For the second quarter of 2012, we incurred approximately $10,000 for workovers, well service units and repairs which accounted for approximately $1.16 per BOE that were capitalized.

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.

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 no revenues for the second quarters of 2013 and 2012, due to low natural gas prices which resulted in all wells in the field being shut-in since June 2011.

Presented below is a summary of operating costs for the quarters ended June 30, 2012 and 2013:


	2012		2013
Related party- cost of production	$	—	$	—

Unrelated parties:
Compressor rental		—		—
Pumper costs		—		—
Transportation		—		—
Property taxes		1,392		1,275
Land rent, utilities, repairs and other		2,268		2,867

Total unrelated party costs		3,660		4,142

Total	$	3,660	$	4,142

Depreciation expense related to the gas gathering system was $11,055 for the second quarter of both 2012 and 2013.

General and Administrative

Presented below is a summary of general and administrative expenses for the quarters ended June 30, 2012 and 2013:


	2012		2013		Change
Director fees	$	30,000	$	900	$	(29,100	)
Investor relations		84,227		44,530		(39,697	)
Legal, auditing and transfer agent		28,562		66,300		37,738
Consulting fees:
Related parties		155,750		30,750		(125,000	)
Unrelated parties		55,059		—		(55,059	)
Other administrative expense		29,249		19,192		(10,057	)
Depreciation		142		—		(142	)

Total general and administrative expenses	$	382,989	$	161,672	$	(221,317	)

General and administrative expenses decreased by $221,317, primarily due to an effort by management to cut costs. Our management has provided accounting services and all needed administrative services for regulatory compliance and no cost to the Company. In addition, we had no acquisition costs or due diligence costs for the second quarter 2013.

The monthly charge of $10,000 under an agreement with DNR, a related party, whereby executive level expertise is provided for our existing and prospective oil and properties. The total monthly charge under the operating agreement is $18,000, of which $8,000 is allocated to lease operating expense. DNR is an affiliate of Charles B. Davis, an executive officer and director of the Company.

Loss from operations

Loss from operations for the second quarter of 2012 was $280,148 compared to a loss of $5,956 for the second quarter of 2013. The decrease in the loss was primarily due to the $221,317 savings in general and administrative expenses (see above).

Interest Expense

Interest expense increased to $36,304 in the second quarter of 2013 from $14,556 in the second quarter of 2012, an increase of $21,748. This increase was primarily due to an increase in borrowing that in the second quarter of 2013.

Results of Operations for the Six-Months Ended June 30, 2012 and 2013

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, 2012 and 2013.

Oil and Gas Producing Activities

As discussed above, 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 Presented below is a summary of our oil and gas operations for the six months ended June 30, 2012 and 2013:


	2012			2013
Oil Sales	$	861,319		$	757,878
Natural Gas Sales		174,076			216,114

Total Revenue		1,035,395			973,992

Production Taxes		(84,326	)		(76,865	)
Lease Operating Expense		(401,653	)		(341,400	)
Depreciation, depletion, amortization and accretion		(336,837	)		(323,335	)

Net	$	212,579		$	232,392

Net barrels of oil sold		10,565			9,380
Net mcf of gas sold		43,320			42,405

Average price for oil (bbl)	$	81.53		$	80.80

Average price for gas (mcf)	$	4.02		$	5.09

Lease operating expense per BOE	$	22.58		$	20.82

DD&A per BOE	$	18.94		$	19.66

Our oil sales were primarily attributable to our properties in Kansas and Wyoming. The average oil price for the first six-months of 2013 was $80.80 per barrel but ranged from a high of $85.82 in February to a low of $77.79 in May. 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. The oil revenue for the first six months of 2013 was down compared to the same period 2012. Although we received a slightly lower average oil price in 2013 we sold 115 barrels less than we produced or $9,292 at our average price per barrel. In addition in January 2013, the number of barrels produced was down by an estimated 650 barrels based on bad weather not allowing for the oil to be picked up in Kansas. The wells shut in for about 10 days as the tanks were full. The oil was picked up in late January and production was resumed. Our average natural gas price, including proceeds from sales of natural gas liquids, amounted to $5.09 per Mcf for the first six-months of 2013. 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.

Production taxes were approximately 8% of our oil and gas sales for the six months ended June 30, 2013 and 2012. Lease operating expense averaged $20.82 per BOE. The lease operating expense averaged $22.58 per BOE for the same period 2012. Many of the wells included in our acquisition have been producing for a decade or longer and the cost of workovers and normal maintenance are charged to expense in the period the costs are incurred. For the six months ended June 30, 2013, we incurred approximately $79,000 for workovers, well service units and repairs, which accounted for approximately $4.80 per BOE of our lease operating expenses that was capitalized based on increased production the wells. For the six months ended June 30, 2012, we incurred approximately $97,000 for workovers, well service units and repairs which accounted for approximately $5.45 per BOE that were capitalized.

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 and restated purchase and sale 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 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

Presented below is a summary of operating costs for the quarters ended June 30, 2012 and 2013:


	2012		2013
Related party- cost of production	$	—	$	—

Unrelated parties:
Compressor rental		—		—
Pumper costs		—		—
Transportation		—		—
Property taxes		2,785		2,550
Land rent, utilities, repairs and other		4,535		5,135

Total unrelated party costs		7,320		7,685

Total	$	7,320	$	7,685

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 and 2013. Depreciation expense related to the gas gathering system was $22,110 for the first six-months of both 2012 and 2013.

In July 2011, we acquired the entire field of coal bed methane wells as part of our $11 million acquisition. While these wells are not economic at current prices being received for natural gas related to the production capability from the existing geologic formation, we have geologic and engineering data that suggest substantial gas reserves exist on these properties by drilling new wells and/or recompleting the existing wells to several new geologic formations. We expect to further evaluate these properties and, if warranted, execute our development plans within the next three years seeking to exploit the value of the properties and the gas gathering system. As of June 30, 2013, the capitalized cost of the coal bed methane leases is $93,512 and the net capitalized cost of the gas gathering system is $167,197. As of June 30, 2012, the capitalized cost of the coal bed methane leases is $248,295 and the net capitalized cost of the gas gathering system is $214,416.

General and Administrative

Presented below is a summary of general and administrative expenses for the six months ended June 30, 2012 and 2013:


	2012		2013		Change
Director fees	$	60,000	$	1,350	$	(58,650	)
Investor relations		130,031		75,427		(54,604	)
Legal, auditing and transfer agent		77,642		96,890		19,248
Consulting and executive services:
Related parties		316,500		61,500		(255,000	)
Unrelated parties		76,504		—		(76,504	)
Other administrative expenses		42,795		40,562		(2,233	)
Depreciation		285		285		—

Total general and administrative expenses	$	703,757	$	276,014	$	(427,743	)

General and administrative expenses decreased by $427,743 for the first six months of 2013 compared to 2012, primarily due to decreases in directors’ fees of $58,650, investor relations of $54,604, consulting and executive services with related parties of $255,000, unrelated party consulting fees of $76,504, and other administrative costs of $2,233. These decreases were offset by an increase in legal, auditing, and transfer agent of $19,248.

The monthly charge of $10,000 under an agreement with DNR, whereby executive level expertise is provided for our existing and prospective oil and properties. The total monthly charge under the operating agreement is $18,000, of which $8,000 is allocated to lease operating expense. DNR is an affiliate of Charles B. Davis, an executive officer and director of the Company.

Income (loss) from operations

(Loss) from operations for the first six-months of 2013 was $(72,468) compared to income from operations of $12,440 for the first six-months of 2012. The decrease of $84,908 was primarily due to the gain on sale of oil and gas properties of $533,048 in 2012, the reduction in items discussed above relating to the oil and natural gas operations, gas gathering activities, and general and lower administrative expenses.

Interest Expense

Interest expense increased from $32,401 in the first six months of 2012 to $61,800 in the first six months of 2013, an increase of $29,399. This increase was due to higher weighted average borrowings in the first six months of 2013.

Liquidity and Capital Resources

We had a working capital deficit as of June 30, 2013 of $1,973,449, compared to a working capital deficit of $1,938,752 at December 31, 2012. The approximately $35,000 increase in our working capital deficit resulted from a combination of new debt of a $1,000,000 in current liabilities, small decease in working capital of approximately $35,000, and the restructure of $400,000 of existing debt to long-term and a long-term note of $600,000 as part of the redemption of the preferred stock.

We had negative operating cash flow of $(67,267) for the first six months of 2013 compared to operating cash flow of approximately $75,433 for the same period of 2012. The net decrease in operating cash flow of $(142,700) was due to a number of different factors both positive and negative. We had a decrease of our income by $114,526 with a net loss of $134,267 in the six months ended June 30, 2013 compared to net loss of $19,741 in the six months ended June 30, 2012, We had a decrease in depreciation, depletion, amortization and accretion of $13,502, and changes in working capital of a decrease in cash flow of $295,781.

For the six months ended June 30, 2013, we used $188,161 of cash flows related to investing activities for capital expenditures. For the six months ended June 30, 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 proceeds from the sale of oil and gas properties were partially offset by capital expenditures of $646,000.

For the six months ended June 30, 2013 our financing activities generated net cash of $248,925, we had net borrowings of approximately $1,040,935. These funds were needed to fund current bills, preferred stock dividend, preferred stock redemption, debt payments and were provided by related parties. For the six months ended June 30, 2012, our financing activities used net cash of $(306,464) as we borrowed $400,000 and repaid borrowings of $264,619, paid preferred stock dividend of $391,875, and offering costs of $50,000.

During the six months ended June 30, 2013, the Company issued 45,000 shares of common stock for payment of fees. The Board of Directors has declared the semi-annual dividend payable to preferred shareholders of record as of March 31, 2013. The Board of Directors declared the preferred dividend of $391,875 on April 26, 2013 and paid in cash on April 28, 2013.

Effective June 28, 2013, several holders of the Company’s 15% Series A1 Convertible Preferred Stock (“Series A1 Preferred Stock”) elected to convert shares of such stock into the Company’s common stock at a redemption price of $0.75 per common share. In connection with these redemptions all such holders agreed to waive all dividend rights on their shares of Series A1 Preferred Stock subsequent to March 30, 2013. Information regarding the conversions is set forth below:


Name of Holder	Number of Shares of Series A1 Preferred Stock Converted		Number of Common Shares Issued
Burlingame Equity Investors II, LP		16		100,800
Burlingame Equity Investors Master Fund, LP		184		1,159,200
Charles B. Davis*		100		1,333,333
Tucker Family Investments LLLP		25		333,333
Mark Venjohn		10		133,333
Pete Haman		35		466,667
Nicholas L. Scheidt*		100		1,333,333
Michael J. Finney		5		66,667
William and Sara Kroske		2.5		33,333
Michael A. Geller		10		133,333
John H. Rosasco		10		133,333

*	Executive Officer and Director of the Company


Name of Holder	Cash Consideration		Promissory Note – Principal		Series A1 Preferred Shares Cancelled
Burlingame Equity Investors II, LP	$	4,000	$	48,000		16
Burlingame Equity Investors Master Fund, LP	$	46,000	$	552,000		184

As of June 30, 2013, we had cash and equivalents of approximately $400 and approximately $300,000 in receivables due from oil and natural gas operations in the next 60 days. Based on the current prices received from the sale of our oil and natural gas, the cash flows may not be adequate to cover all of our operating, general, administrative and interest costs. 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. However, without financing for these acquisitions they will not be possible.

In order to execute our plan to acquire additional interests in oil and gas properties that meet our objectives, we need 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. There can be no assurance that we will continue to generate any proceeds from the sale of our properties.

We are currently in 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 2013 or thereafter.

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, and (v) review and implement other opportunities to reduce general, administrative and operating expenses.

Contractual Obligations and Commercial Commitments

As of June 30, 2013, we have future minimum lease payments of approximately $7,000. This amount is payable during the years ending June 30, 2014, 2015, 2016, 2017 and after 2017 in the amounts of $1,000, $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. The Colorado and Kansas properties provide for additional consideration that is payable to the related party sellers if proved producing reserves are increased relating to these properties through drilling or recompletion activities over a period of ten years after the closing date. First to the extent that oil reserves increase, the sellers are entitled to additional consideration of $250,000 for each increase of 20,000 net barrels. Second, to the extent that oil and gas prices increase, the sellers are entitled to additional consideration as the targeted price thresholds are exceeded for periods of 61 days. The increase in purchase price for the Kansas and Colorado properties is limited to a maximum of $5 million.

The acquired properties that are located in Wyoming and Montana provide a similar formula as used for the Colorado and Kansas properties that could result in an obligation for additional purchase consideration to the extent that we perform future drilling or recompletion activities in formations that were not producing as of the

September 29, 2011 closing date. Furthermore, if we sell properties where reserves have been proved up through drilling or recompletion, the sellers have retained an interest of 70% in the net sales proceeds (after we receive a recovery of 125% of the original purchase allocation in the amended and restated purchase agreement). The increase in purchase price for all properties (Colorado, Kansas, Wyoming and Montana) is limited to a maximum of $25 million.

Due to consideration retained by the related party sellers from sales of properties through the first quarter of 2012, and $250,000 of consideration payable in December 2012 due to a sustained increase in oil prices over $90 per barrel, the maximum future consideration was reduced by approximately $5.0 million to $20.0 million as of June 30, 2013.

New Accounting Pronouncements

•

Present (either on the face of the statement where net income is presented or in the notes) the effects on the line items of net income of significant amounts reclassified out of accumulated other comprehensive income - but only if the item reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period; and

•

In July 2012, the FASB issued ASU 2012-02, “Intangibles – Goodwill and Other (Topic 350): Testing Indefinite-Lived Intangible Assets for Impairment” in Accounting Standards Update No. 2012-02. This update amends ASU 2011-08, Intangibles – Goodwill and Other (Topic 350): Testing Indefinite-Lived Intangible Assets for Impairment and permits an entity first to assess qualitative factors to determine whether it is more likely than not that an indefinite-lived intangible asset is impaired as a basis for determining whether it is necessary to perform the quantitative impairment test in accordance with Subtopic 350-30, Intangibles - Goodwill and Other - General Intangibles Other than Goodwill. The amendments are effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012. Early adoption is permitted, including for annual and interim impairment tests performed as of a date before July 27, 2012, if a public entity’s financial statements for the most recent annual or interim period have not yet been issued or, for nonpublic entities, have not yet been made available for issuance. The adoption of ASU 2012-02 is not expected to have a material impact on our financial position or results of operations.

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, 2013, 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/A for the year ended December 31, 2012, 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 third fiscal quarter that has materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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, 2012. The risk factors in our Annual Report on Form 10-K 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.

None

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		Certificationof the Principal Executive Officer pursuant to 18 U.S.C. Section 1350.

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

101		The following materials are filed herewith: (i) XBRL Instance, (ii) XBRL Taxonomy Extension Schema, (iii) XBRL Taxonomy Extension Calculation, (iv) XBRL Taxonomy Extension Labels, (v) XBRL Taxonomy Extension Presentation, and (vi) XBRL Taxonomy Extension Definition. In accordance with Rule 406T of Regulation S-T, the information in these exhibits is furnished and deemed not filed or a part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Exchange Act of 1934, and otherwise is not subject to liability under these sections and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, except as expressly set forth by the specific reference in such filing.

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/ Nicholas Scheidt, CEO
Nicholas L Scheidt, Principal Executive Officer
Dated: August 9, 2013

By:		/s/ Donald W. Prosser, CFO
Donald W. Prosser, Principal Financial and Accounting Officer
Dated: August 9, 2013

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	8th grade Avg

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company