ARETE INDUSTRIES INC - FORM 10-Q

Attached files

Attached files

ARETE INDUSTRIES INC Reports

Also read

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

Table of Contents

Table of Contents

file	filename
EX-32.2 - EX-32.2 - ARETE INDUSTRIES INC	d399005dex322.htm
EX-32.1 - EX-32.1 - ARETE INDUSTRIES INC	d399005dex321.htm
EX-31.1 - EX-31.1 - ARETE INDUSTRIES INC	d399005dex311.htm
EX-31.2 - EX-31.2 - ARETE INDUSTRIES INC	d399005dex312.htm
EXCEL - IDEA: XBRL DOCUMENT - ARETE INDUSTRIES INC	Financial_Report.xls

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 September 30, 2012

¨	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. See definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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 November 9, 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 - 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, 2011 and September 30, 2012


	2011			2012
ASSETS
Current Assets:
Cash and equivalents	$	219,566		$	447,735
Receivable from DNR Oil & Gas, Inc.:
Oil and gas sales, net of production costs		165,283			270,056
Other		15,597			49,766
Prepaid expenses and other		207,338			120,306

Total Current Assets		607,784			887,863

Property and Equipment:
Oil and gas properties, at cost, successful efforts method:
Proved properties		9,056,032			9,284,398
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			10,059,403
Less accumulated depreciation, depletion and amortization		(525,154	)		(1,122,181	)

Net Property and Equipment		9,283,323			8,937,222

TOTAL ASSETS	$	9,891,107		$	9,825,085

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

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED BALANCE SHEETS, Continued

December 31, 2011 and September 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		$	250,000
Gas gathering operating costs		416,835			436,403
Operator fees and other		151,748			141,748
Unrelated parties		92,019			82,250
Preferred stock dividends payable		—			391,875
Notes and advances payable:
Directors and affiliates		109,319			670,950
Unrelated parties		250,000			250,000
Accrued interest expense		88,303			50,655
Director fees payable in common stock		90,000			31,875
Accrued consulting services payable in common stock		18,750			48,750
Current portion of asset retirement obligations		15,398			42,419
Other accrued costs and expenses		216,061			269,579

Total Current Liabilities		2,275,224			2,666,504


Long-Term Liabilities:
Asset retirement obligations, net of current portion		637,842			614,795
Payable to DNR Oil & Gas, Inc.		—			250,000

Total Long-Term Liabilities		637,842			864,795

Total Liabilities		2,913,066			3,531,299

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 $5,616,875 in 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	)		(15,880,681	)

Total Stockholders’ Equity		6,978,041			6,293,786

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	9,891,107		$	9,825,085

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 Nine-Months Ended September 30, 2011 and 2012


	Quarters Ended						Nine-Months Ended
	September 30:						September 30:
	2011			2012			2011			2012
Revenues:
Oil and natural gas sales	$	436,764		$	645,069		$	436,764		$	1,680,464
Sale of oil and natural gas properties		—			—			—			533,048
Gas gathering income		—			—			45,639			—

Total revenues		436,764			645,069			482,403			2,213,512

Operating Expenses:
Oil and gas producing activities:
Lease operating expenses		185,469			188,483			185,469			590,136
Production taxes		36,903			57,023			36,903			141,349
Depreciation, depletion, amortization and accretion		78,066			258,121			78,066			594,957
Gas gathering:
Cost of operations:
Related Party		—			—			30,815			—
Unrelated parties		3,722			4,561			84,280			11,881
Depreciation		11,055			11,055			33,165			33,165
General and administrative expenses:
Director fees		30,000			1,875			90,000			61,875
Investor relations		77,346			68,439			302,668			198,470
Acquisition investigation and due diligence		14,101			—			514,579			—
Legal, auditing and professional services		36,059			54,209			122,028			131,851
Consulting and executive services:
Related parties		86,375			35,750			319,125			352,250
Unrelated parties		44,750			55,782			86,602			132,286
Other administrative expenses		13,168			23,060			38,864			65,856
Depreciation		—			142			—			427

Total operating expenses		617,014			758,500			1,922,564			2,314,503

Operating loss		(180,250	)		(113,431	)		(1,440,161	)		(100,991	)
Other income (expense):
Gain on sale of Separate Interests		2,479,934			—			2,479,934			—
Interest income		196			5			475			225
Interest expense		(148,936	)		(14,280	)		(183,378	)		(46,681	)

Income (loss) before income taxes		2,150,944			(127,706	)		856,870			(147,447	)
Income tax benefit (expense)		—			—			—			—

Net income (loss)	$	2,150,944		$	(127,706	)	$	856,870		$	(147,447	)

Net Income (loss) Applicable to Common Stockholders:
Net income (loss)	$	2,150,944		$	(127,706	)	$	856,870		$	(147,447	)
Accrued preferred stock dividends		—			(195,937	)		—			(587,812	)

Net income (loss) applicable to common stockholders	$	2,150,944		$	(323,643	)	$	856,870		$	(735,259	)

Earnings (Loss) Per Share Applicable to Common Stockholders:
Basic	$	0.28		$	(0.04	)	$	0.13		$	(0.09	)

Diluted	$	0.28		$	(0.04	)	$	0.13		$	(0.09	)

Weighted Average Number of Common Shares Outstanding:
Basic		7,715,000			7,980,000			6,575,000			7,845,000

Diluted		7,715,000			7,980,000			6,575,000			7,845,000

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

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

For the Nine-Months Ended September 30, 2012


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

Issuance of common stock for Board of Directors’ fees		—		—		65,605		120,000		—			120,000
Issuance of common stock to related parties for consulting services		—		—		135,972		110,000		—			110,000
Issuance of common stock to unrelated parties:
For accrued interest		—		—		7,750		10,462		—			10,462
For consulting services		—		—		6,000		6,480		—			6,480
Preferred stock dividends declared		—		—		—		—		(783,750	)		(783,750	)
Net loss		—		—		—		—		(147,447	)		(147,447	)

Balances, September 30, 2012		522.5	$	5,023,371		7,979,803	$	17,151,096	$	(15,880,681	)	$	6,293,786

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

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Nine-Months Ended September 30, 2011 and 2012


	2011			2012
Cash Flows from Operating Activities:
Net loss	$	856,870		$	(147,447	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		97,782			600,762
Accretion of discount on asset retirement obligations		13,458			27,788
Gain on sale of oil and gas properties		(2,479,934	)		(533,048	)
Common stock issued in exchange for services		896,376			246,942
Common stock issued in exchange for accrued interest		—			10,462
Changes in operating assets and liabilities:
Accounts receivable		(969,372	)		(159,594	)
Prepaid expenses and other		—			88,282
Accounts payable		683,169			(201	)
Accrued costs and expenses		179,143			(6,557	)

Net cash provided by (used in) operating activities		(722,508	)		127,389

Cash Flows from Investing Activities:
Capital expenditures for property and equipment		(5,685,061	)		(843,731	)
Proceeds from sale of oil and gas properties		—			1,108,709
Contingent consideration paid to DNR under sharing arrangement		—			(282,704	)

Net cash used in investing activities		(5,685,061	)		(17,726	)

Cash Flows from Financing Activities:
Proceeds from notes and advance payable		2,102,850			825,000
Principal payments on notes payable		(439,256	)		(264,619	)
Payment of dividends on preferred stock		—			(391,875	)
Proceeds from sale of common stock		203,500			—
Proceeds from sale of preferred stock		5,023,371			—
Payment of preferred stock offering costs		—			(50,000	)

Net cash provided by financing activities		6,890,465			118,506

Net increase in cash and equivalents		482,896			228,169
Cash and equivalents, beginning of period		15,990			219,566

Cash and equivalents, end of period	$	498,886		$	447,735

Supplemental Disclosure of Cash Flow Information:
Cash paid for interest	$	141,996		$	86,827

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	$	1,284,251		$	—

Preferred stock dividends payable	$	—		$	391,875

Payable to DNR Oil & Gas, Inc. for oil and gas property acquisition costs	$	—		$	250,000

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.

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 seeks to focus 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 September 30, 2012, and the results of operations, changes in stockholders’ equity, and cash flows for the quarters and the nine-months ended September 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/A 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/A.

Use of estimates

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

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

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. In the Company’s Consolidated Statement of Operations included in its quarterly report on Form 10-Q for the quarter and the nine-months ended September 30, 2011, the gain on sale of oil and gas properties described in Note 3 of $2,479,934 was included in operating revenue. This amount was reclassified as non-operating income in the accompanying Consolidated Statements of Operations. Reclassifications did not have any impact on the Company’s previously reported working capital, net income (loss), 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 September 30, 2012, the convertible preferred stock had an aggregate liquidation preference of $5,616,875 and was convertible to 1,702,083 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 a material 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 a material 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.

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 on 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 $628,260 for the Properties and $138,468 for the Separate Interests for an aggregate of $766,728. These amounts were treated as a reduction of the carrying costs of the Properties and the Separate Interests.

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


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

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

	$	11,000,000	*(c)*

(a)

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

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

The table below reflects unaudited pro forma results as if the July 29, 2011 acquisition of oil and gas properties had taken place as of January 1, 2011:


	Quarter Ended September 30, 2011				Nine Months Ended September 30, 2011:
	Historical		Pro Forma		Historical		Pro Forma
Total revenue	$	436,764	$	644,957	$	482,403	$	2,187,911

Net income	$	2,150,944	$	2,108,424	$	856,870	$	752,522

Net income applicable to common stockholders	$	2,150,944	$	2,108,424	$	856,870	$	752,522

Earnings per share:
Basic	$	0.28	$	0.27	$	0.13	$	0.11

Diluted	$	0.28	$	0.27	$	0.13	$	0.11

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 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. Except for the sale of the Separate Interests discussed above, 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 $8.3 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		Valuation
	Shares		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. Through the second quarter of 2012, each of the Company’s five directors earned 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. Beginning in the third quarter of 2012, directors are entitled to 300 shares of the Company’s common stock for each meeting attended. Each of the five directors attended two meetings resulting in an obligation for the Company to issue an aggregate of 3,000 shares with an estimated fair value of $1,875.

From January 2012 through June 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. The Company has not yet settled the liabilities for services performed in May through June 2012, but management expects to issue 44,823 shares of the Company’s common stock to settle the remaining liability for $30,000.

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 September 30, 2012, the Company has a liability for directors’ fees of $31,875 which is expected to result in the issuance of 57,431 shares of common stock in the fourth quarter of 2012. Additionally, the Company has a liability for accrued consulting fees of $18,750 which is expected to result in the issuance of 30,000 shares of common stock in the fourth quarter of 2012.

Preferred Stock Dividends

On September 11, 2012 the Board of Directors declared the 15% dividend on the Series A-1 preferred stock which was paid in cash on October 1, 2012. As of September 30, 2012, accrued dividends amounted to $391,875 and are included in current liabilities. 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 March 31, 2013.

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 September 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 nine-months ended September 30, 2011 and 2012, $125,000 related to this consulting contract is included in investor relations expense in the accompanying unaudited consolidated statements of operations. As of September 30, 2012, the unamortized balance of approximately $69,000 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 September 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
Collateralized note payable, interest at 12%		—		425,000

Total officers, directors and affiliates		109,319		670,950

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	$	920,950

On September 29, 2012, the Company borrowed $425,000 under a note agreement that provides for interest at an annual rate of 12% with unpaid principal and interest due on March 29, 2013. The Company also agreed to assign 75% of its operating income from its oil and gas operations and any lease or well sale or any other asset sales to the note holder to secure the debt. The note holder is 100% owned by a consultant and shareholder of the Company. All of the other notes payable shown above are unsecured. Accrued interest on notes and advances payable amounted to $88,303 as of December 31, 2011 and $50,655 as of September 30, 2012.

8.	Asset Retirement Obligations

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

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


Balance, December 31, 2011	$	653,240
Liabilities paid		(33,840	)
Liabilities assumed by buyer of properties		(16,411	)
Accretion expense		27,788
Revisions of prior estimates		26,437

Balance, September 30, 2012		657,214
Less current asset retirement obligations		(42,419	)

Long-term asset retirement obligations	$	614,795

9.	Related Party Cost Reductions

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. 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.

As discussed in Note 5, effective July 1, 2012 the Company reduced the amounts paid for director fees and other related party consulting arrangements. Presented below is a summary of the impact of related party cost reductions implemented during the third quarter of 2012:


	Quarter Ended
	06/30/12		09/30/12		Reduction
Fees payable in cash:
Operator fees	$	69,000	$	54,000	$	15,000
Consulting fees		15,000		—		15,000
Fees payable in shares of common stock:
Director fees		30,000		1,875		28,125
Consulting fees		45,000		—		45,000

	$	159,000	$	54,875	$	103,125

10.

Subsequent events

As discussed in Note 5, on October 1, 2012 the Company paid accrued dividends on preferred stock of $391,875.

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/A 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;

•

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/A. 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 will be 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.

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/A, 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 September 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.

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 nine-months ended September 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.

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

Presented below is a discussion of our results of operations for the quarters ended September 30, 2011 and 2012.

Oil and Gas Producing Activities

On July 29, 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 September 30, 2011 and 2012:


	2011			2012
Oil sales	$	333,618		$	562,001
Natural gas sales		103,146			83,068

Total revenue		436,764			645,069
Production taxes		(36,903	)		(57,023	)
Lease operating expense		(185,469	)		(188,483	)
Depreciation, depletion, amortization and accretion (“DD&A”)		(78,066	)		(258,121	)

Net	$	136,326		$	141,442

Net barrels of oil sold		4,541			8,470
Net mcf of gas sold		16,086			22,060
Net Barrels of Oil Equivalent (“BOE”) sold *		7,222			12,147
Average price per barrel of oil sold	$	73.47		$	66.35

Average price for per mcf of natural gas sold	$	6.41		$	3.77

Lease operating expense per BOE	$	25.68		$	15.52

DD&A per BOE	$	10.81		$	21.25

*	BOE is determined using a ratio of six Mcf of natural gas equal to one barrel of oil equivalent.

Our oil sales are primarily attributable to our properties in Kansas and Wyoming. The average oil price for the third quarter of 2012 of $66.35 per barrel decreased by 9.7% compared to $73.47 per barrel for the third quarter of 2011. Our average natural gas price, including proceeds from sales of natural gas liquids, amounted to $3.77 per Mcf for the third quarter of 2012 which is a decrease of 41.2% compared to $6.41 per Mcf for the third quarter of 2011.

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 for both the second and third quarters of 2012 compared to the first quarter of 2012.

Production taxes were approximately 8.8% of our oil and gas sales for the third quarter of 2012 compared to 8.4% for the third quarter of 2011. Lease operating expense averaged $15.52 per BOE for the third

quarter for 2012 compared to $25.68 per BOE for the third quarter of 2011. 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. Workovers and major repairs are capitalized if the work performed is expected to result in an increase in proved reserves for the well.

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 third quarter of 2011, our DD&A per BOE was $10.81 compared to $21.25 per BOE for the third quarter of 2012. The increase in DD&A during the third quarter of 2012 was $180,055 and was primarily due to a 68% increase in production whereby the third quarter of 2011 only had 2 months of production versus 3 months for the third quarter of 2012. Other factors that resulted in higher DD&A for the 2012 period included adjustments to the well by well purchase price allocation during the fourth quarter of 2011 which increased DD&A during 2012. Additionally, capitalized costs are higher in 2012 compared to 2011 due to capitalized workovers and major repairs to several of the wells, and we revised our estimates for plugging and abandonment costs and reduced our estimates of proved oil and gas reserves for certain wells that we intend to plug and abandon.

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 either the third quarter of 2011 or the third quarter of 2012. Due to a reduction in natural gas prices, all wells in the field have been shut-in since June 2011. Costs incurred with unrelated parties were $3,722 for the third quarter of 2011 compared to $4,561 for the third quarter of 2012. Depreciation expense related to the gas gathering system was $11,055 for the third quarter of both 2011 and 2012.

General and Administrative

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


	2011		2012		Change
Director fees	$	30,000	$	1,875	$	(28,125	)
Investor relations		77,346		68,439		(8,907	)
Acquisition investigation and due diligence		14,101		—		(14,101	)
Legal, auditing and professional services		36,059		54,209		18,150
Consulting and executive services:
Related parties		86,375		35,750		(50,625	)
Unrelated parties		44,750		55,782		11,032
Other administrative services		13,168		23,060		9,892
Depreciation		—		142		142

Total general and administrative expenses	$	301,799	$	239,257	$	(62,542	)

General and administrative expenses decreased by $62,542, primarily due to decreases in related party consulting fees of $50,625, director fees of $28,125, and acquisition investigation and due diligence costs of $14,101.

The decrease in related party consulting fees was primarily due to the elimination of monthly consulting fees of $15,000 payable to two directors and a shareholder effective July 1, 2012, which resulted in a cost reduction of $45,000 for the third quarter of 2012. Additionally, the DNR operator agreement compensation was reduced by $5,000 per month effective July 1, 2012 which resulted in additional savings of $15,000 for the third quarter of 2012. Also, effective July 1, 2012, director fees payable to each of the Company’s five directors was reduced from a monthly fee of $3,000 to a fee equal to 300 shares of the Company’s commons stock for each meeting attended. The fair value of shares issuable under this arrangement was $1,875 resulting in a cost reduction of $28,125 for the third quarter of 2012. Acquisition investigation and due diligence costs of $14,101 were incurred in the third quarter of 2011 and related to the July 2011 oil and gas property acquisition. We did not evaluate any significant acquisitions during the third quarter of 2012 and, accordingly, no costs were incurred. The increase in legal, auditing and professional services expense of $18,150 was primarily due to higher costs associated with SEC filings; and the increase in other administrative expenses of $9,893 was primarily due to new insurance coverage for officer and director liability and higher travel costs in 2012.

Interest Expense

Interest expense decreased from $148,936 for the third quarter of 2011 to $14,280 for the third quarter of 2012, a decrease of $134,656. Interest expense for the third quarter of 2012 was primarily related to seller and third party financing related to the purchase of oil and gas properties.

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

Results of Operations for the Nine-months Ended September 30, 2011 and 2012

Presented below is a discussion of our results of operations for the nine-months ended September 30, 2011 and 2012.

Oil and Gas Producing Activities

On July 29, 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 nine-months of 2011 we only had oil and gas producing activities for the period from July 29, 2011 through September 30, 2011. Presented below is a summary of our oil and gas operations for the nine-months ended September 30, 2012:


	2011			2012
Oil sales	$	333,618		$	1,423,320
Natural gas sales		103,146			257,144

Total revenue		436,764			1,680,464
Production taxes		(36,903	)		(141,349	)
Lease operating expense		(185,469	)		(590,136	)
Depreciation, depletion, amortization and accretion (“DD&A”)		(78,066	)		(594,957	)

Net	$	136,326		$	354,022

Net barrels of oil sold		4,541			19,035
Net mcf of gas sold		16,086			65,381
Net Barrels of Oil Equivalent (“BOE”) sold		7,222			29,932
Average price per barrel of oil sold	$	73.47		$	74.77

Average price for per mcf of natural gas sold	$	6.41		$	3.93

Lease operating expense per BOE	$	25.68		$	19.72

DD&A per BOE	$	10.81		$	19.88

The average oil price for the 2012 period was $74.77 per barrel an increase of 1.8% compared to $73.47 per barrel for the 2011 period. Our average natural gas price, including proceeds from sales of natural gas liquids, amounted to $3.93 per Mcf for 2012 period, which is a decrease of 38.7% compared to $6.41 per Mcf for the 2011 period.

Production taxes were approximately 8.4% of our oil and gas sales for each of the 2012 and 2011 periods. Lease operating expense averaged $19.72 per BOE for the 2012 period compared to $25.68 per BOE for the 2012 period.

For the 2012 period, our DD&A per BOE was $19.88 compared to $10.81 per BOE for the 2011 period. The increase in DD&A during the 2012 period was $516,891 and was primarily due to a 314% increase in production whereby the 2011 period only had 2 months of production versus 9 months for the 2012 period. Other factors that resulted in higher DD&A for the 2012 period included adjustments to the well by well purchase price allocation during the fourth quarter of 2011, capitalized costs were higher due to capitalized workovers and major repairs to several of our wells, and we revised our estimates for plugging and abandonment costs and reduced our estimates of proved oil and gas reserves for certain wells that we intend to plug and abandon.

During the first quarter of 2012, we sold one of our producing properties, 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 in July 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 nine-months of 2011 compared to no revenues for the first nine-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 nine-months ended September 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		4,171		4,178		(0.2	%)
Land rent, utilities, repairs and other		10,106		7,703		(23.8	%)

Total unrelated party costs		84,280		11,881		(85.9	%)

Total	$	115,095	$	7,320		(93.6	%)

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 first nine-months of 2012. Depreciation expense related to the gas gathering system was $33,165 for the first nine-months of both 2011 and 2012.

In July 2011, we acquired the entire field of coal bed methane wells as part of our property acquisition discussed above. While these wells are not economic at current prices being received for natural gas related to the production capability from the existing geologic formation, we have geologic and engineering data that suggest gas reserves exist on these properties by drilling new wells and/or recompleting the existing wells to several new geologic formations. While we believe that reserves exist, we do not expect to undertake any drilling activities on this property until natural gas prices increase significantly. We currently believe we should be able to recover our net capitalized costs related to these properties and the related gas gathering system. However, we are continuing to evaluate our alternatives and there is a possibility that an impairment charge will be required in the future.

General and Administrative

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


	2011		2012		Change
Director fees	$	90,000	$	61,875	$	(28,125	)
Investor relations		302,668		198,470		(104,198	)
Acquisition investigation and due diligence		514,579		—		(514,579	)
Legal, auditing and professional services		122,028		131,851		9,823
Consulting and executive services:
Related parties		319,125		352,250		33,125
Unrelated parties		86,602		132,286		45,684
Other administrative expenses		38,864		65,856		26,992
Depreciation		—		427		427

Total general and administrative expenses	$	1,473,866	$	943,015	$	(530,851	)

General and administrative expenses decreased by $530,851 for the first nine-months of 2012 compared to the similar period in 2011, primarily due to decreases in acquisition investigation and due diligence costs of $514,579, investor relations of $104,198, and director fees of $28,125. These decreases were offset by increases in consulting and executive services totaling $78,809, and other administrative costs of $26,992.

The decrease in acquisition investigation and due diligence costs of $514,579 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 July 2011. We did not evaluate any significant acquisitions during the first nine-months of 2012 and, accordingly, no costs were incurred. The decrease in investor relations costs of $104,198 was due to substantial activities related to investment banking, market information and shareholder communication services that were performed in the first nine-months of 2011 in preparation for the acquisition that was consummated in July 2011. Effective July 1, 2012, director fees payable to each of the Company’s five directors was reduced from a monthly fee of $3,000 to a fee equal to 300 shares of the Company’s commons stock for each meeting attended. The fair value of shares issuable under this arrangement was $1,875 resulting in a cost reduction of $28,125 for the first nine-months of 2012. The increase in consulting fees paid to unrelated parties of $45,684 was primarily attributable to an increase in financial reporting services for the first nine-months of 2012. Consulting and executive services incurred with related parties increased from $319,125 for the first nine-months of 2011 to $352,250 for the first nine-months of 2012. The following arrangements for consulting and executive services with related parties were in place during the first nine-months of 2012:

•

Effective October 1, 2011, the Company entered into an Operator Agreement with DNR to provide executive level operations expertise for our existing and prospective oil and properties. The Operator Agreement provided for a monthly charge of $23,000 through June 2012 and a reduction to $18,000 beginning in July 2012. The total charge under the Operator Agreement was $192,000 for the first nine-months of 2012, of which $72,000 was allocated to lease operating expense and $120,000 was allocated to general and administrative expenses. DNR is an affiliate of Charles B. Davis, an executive officer and director of the Company.

•

For the period from January 2012 through June 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 nine-months ended September 30, 2012, the Company incurred aggregate fees of $90,000 under this arrangement.

•

During the first nine-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 common stock with a fair market value of $50,000.

•

For the period from January 2012 through July 2012, the Company incurred executive and accounting fees of $35,000 from an officer and director. The Company also pays rent to an officer and director for the Company’s office in the amount of $250 per month.

Interest Expense

Interest expense decreased from $183,378 for the first nine-months of 2011 to $46,681 for the first nine-months of 2012, a decrease of $136,697. Interest expense for the first nine-months of 2012 was primarily related to seller and third party financing related to the purchase of oil and gas properties. This debt was partially refinanced with approximately $5 million of the net proceeds from the issuance of preferred stock in September 2011.

Liquidity and Capital Resources

We had a working capital deficit as of September 30, 2012 of approximately $1,779,000, compared to a working capital deficit of $1,667,000 at December 31, 2011. We generated positive operating cash flow of approximately $127,000 for the first nine-months of 2012 compared to negative operating cash flow of approximately $723,000 for the first nine-months of 2011.

For the first nine-months of 2011, our cash flows related to investing activities consisted solely of cash payments totaling $5,685,000 for the acquisition of oil and gas properties in July 2011. For the first nine-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 $844,000, of which approximately $618,000 was acquisition costs paid to a related party for the properties acquired in July 2011.

For the first nine-months of 2011, we had net borrowings of approximately $1,664,000 and we received proceeds from the sale of common stock of approximately $204,000. 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 July 2011. For the first nine-months of 2012, our financing activities provided net cash of approximately $119,000. During the first nine-months of 2012, we borrowed $825,000 and repaid borrowings of approximately $265,000. During the first nine-months of 2012, we also paid approximately $392,000 for dividends on our preferred stock and $50,000 of offering costs that were incurred in connection with our 2011 private placement of preferred stock.

On September 29, 2012, the Company borrowed $425,000 under a note agreement that provides for interest at an annual rate of 12% with unpaid principal and interest due on March 29, 2013. The Company also agreed to assign 75% of its operating income from its oil and gas operations and any lease or well sale or any other asset sales to the note holder to secure the debt. The note holder is 100% owned by a consultant and shareholder of the Company. The net proceeds from this loan were primarily used to pay approximately $392,000 of preferred stock dividends that were declared in September 2012 and paid on October 1, 2012.

As of September 30, 2012, we had cash and equivalents of approximately $448,000. 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, except for estimated drilling costs of $150,000 for a well that is expected to be drilled

in December 2012. However, if we can obtain adequate financing we expect to incur up to approximately $1,000,000 during the first half of 2013 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 July 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 regarding 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 and beyond.

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 September 30, 2012, we have future minimum lease payments of approximately $8,000. This amount is payable during the years ending September 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 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.

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 sustained increases in oil prices over $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 September 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 a material impact on the Company’s 2012 financial statements.

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 September 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/A 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 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, 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.

Not Applicable

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.

101.INS		XBRL Instance Document

101.SCH		XBRL Taxonomy Extension Schema document

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

101.LAB		XBRL Taxonomy Extension Label Linkbase Document

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

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: November 14, 2012

By:		/s/ John Herzog, Interim CFO
John Herzog, Interim Principal Financial and Accounting Officer
Dated: November 14, 2012

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company