UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

S QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2011

 

£ TRANSITION REPORT UNDER SECTION 13 OR 15(D) OF THE EXCHANGE ACT

For the transition period from _____ to _____

 

OSAGE EXPLORATION AND DEVELOPMENT, INC.

(Exact name of small business issuer as specified in its charger)

 

Delaware	0-52718	26-0421736
(State or other jurisdiction of incorporation or organization)	(Commission File No.)	(I.R.S. Employer Identification No.)

 

2445 5th Avenue Suite 310 San Diego, CA 92101 (Address of principal executive offices)

(619) 677-3956 (Issuer’s telephone number)

 

Check whether the issuer (1) filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the past 12 month (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes S           No £

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes S           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 in Rule 12b-2 of the Exchange Act.

 

Large Accelerated Filer £      Accelerated Filer £

Non-Accelerated Filer £      Smaller Reporting Company S

 

Indicate by check mark whether the registrant is a shell company (as defined in section 12b-2 of the Exchange Act)

Yes £      No S

 

The number of outstanding shares of the registrant’s Common Stock, $0.0001 par value, as of November 10, 2011 was 47,799,775.

 

  

 

OSAGE EXPLORATION AND DEVELOPMENT, INC. AND SUBSIDIARY

 

TABLE OF CONTENTS

 

		Page
PART I – FINANCIAL INFORMATION
Item 1.	Financial Statements (unaudited)	1
	Consolidated Balance Sheets; September 30, 2011 and December 31, 2010 (audited)	1
	Consolidated Statements of Operations and other Comprehensive Income/(Loss); Three and Nine Months ended September 30, 2011 and 2010	2
	Consolidated Statements of Cash Flows; Three and Nine Months ended September 30, 2011 and 2010	3
	Notes to Consolidated Financial Statements	4
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	10
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	20
Item 4.	Controls and Procedures	20
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	21
Item 1.A.	Risk Factors	21
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	21
Item 3	Default upon Senior Securities	21
Item 4	Removed and Reserved	21
Item 5	Other Information	22
Item 6	Exhibits	22
Signatures		22

  

 

PART I. FINANCIAL INFORMATION

 

Item 1. Financial Statements

 

OSAGE EXPLORATION AND DEVELOPMENT, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

 

		2011				2010
		(unaudited)
ASSETS
Current Assets:
Cash and equivalents		$	2,885,132			$	307,566
Accounts receivable, net of $0 allowance			295,878				74,678
Prepaid expenses			98,796				39,441
Total Current Assets			3,279,806				421,685
Property and Equipment, at cost:
Oil and gas properties and equipment, Successful Efforts Method			3,119,396				2,818,833
Capitalized asset retirement costs			46,146				46,146
Other property & equipment			76,671				54,861
			3,242,213				2,919,840
Less: accumulated depletion, depreciation and amortization			(1,239,598	)			(939,639	)
			2,002,615				1,980,201
Bank CD pledged for bond			30,000				30,000
Note receivable			11,000				—
Total Assets		$	5,323,421			$	2,431,886
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable		$	217,201			$	202,880
Accrued expenses			870,308				872,308
Total Current Liabilities			1,087,509				1,075,188
Liability for Asset Retirement Obligations			59,399				57,746
Total Liabilities			1,146,908				1,132,934
Commitments and Contingencies
Stockholders' Equity:
Common stock, $0.0001 par value, 190,000,000 shares authorized; 47,799,775 and 46,649,775 shares issued and outstanding			4,780				4,665
Additional-Paid-in-Capital			12,080,729				11,795,844
Stock Purchase Notes Receivable			(95,000	)			(95,000	)
Accumulated Deficit			(7,525,775	)			(10,093,679	)
Accumulated Other Comprehensive Loss - Currency Translation Loss			(288,221	)			(312,878	)
Total Stockholders' Equity			4,176,513				1,298,952
Total Liabilities and Stockholders' Equity		$	5,323,421			$	2,431,886

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 

OSAGE EXPLORATION AND DEVELOPMENT, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

  

		Three Months Ended September 30,								Nine Months Ended September 30,
			2011				2010				2011				2010
Operating Revenues
Oil		$	382,059			$	376,555			$	1,395,192			$	1,068,373
Pipeline			472,141				91,392				1,063,202				198,685
Total Operating Revenues			854,200				467,947				2,458,394				1,267,058
Operating Costs and Expenses
Operating			283,201				169,644				702,378				458,657
General and Administrative			419,263				354,258				1,188,643				1,054,655
Equity Tax			35,483				75,619				405,935				1,007,567
Depreciation, Depletion and Accretion			112,900				89,995				322,607				267,402
Stock Based Compensation			150,000				39,300				250,000				39,300
Total Operating Expenses			1,000,847				728,816				2,869,563				2,827,581
Operating Loss			(146,647	)			(260,869	)			(411,169	)			(1,560,523	)
Other Income (Expenses):
Interest Income			4,411				546				6,080				2,756
Interest Expense			(551	)			(513	)			(136,653	)			(1,574	)
Gain from Assignment of Leases							—				3,109,646
Income/ (Loss) before Income Taxes			(142,787	)			(260,836	)			2,567,904				(1,559,341	)
Provision for Income Taxes			—				—				—				—
Net Income/ (Loss)			(142,787	)			(260,836	)			2,567,904				(1,559,341	)
Other Comprehensive Income, net of tax:
Foreign Currency Translation Adjustment			17,861				75,015				24,657				182,959
Comprehensive Income/ (Loss)		$	(124,926	)		$	(185,821	)		$	2,592,561			$	(1,376,382	)
Basic and Diluted Income/ (Loss) per Share		$	(0.00	)		$	(0.01	)		$	0.05			$	(0.03	)
Weighted average number of common share and common share equivalents used to compute basic and dilluted Loss per Share			47,576,949				45,599,499				47,084,024				45,875,709

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 

OSAGE EXPLORATION AND DEVELOPMENT, INC. AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

		2011				2010
Cash flows from Operating Activities:
Net Income/ (Loss)		$	2,567,904			$	(1,559,341	)
Adjustments to reconcile net income/ (loss) to net cash (used)/provided by operating activites:
Shares issued for services			250,000				39,300
Shares issued for interest			35,000
Gain on Assignment of Leases			(3,109,646	)
Accretion of Asset Retirment Obligation			1,653				1,503
Provision for depletion, depreciation amortization and valuation allowance			322,607				267,402
Changes in operating assets and liabilities:
(Increase)/Decrease in accounts receivable			(220,357	)			146,343
Increase in other current assets			(32,381	)			—
Increase in prepaid expenses			(28,832	)			(21,912	)
Increase in accounts payable and accrued expenses			14,531				885,103
Net cash used by operating activities			(199,521	)			(241,602	)
Cash flows from Investing Activities:
Pipeline reimbursement by operator			—				154,289
Net proceeds from assignment of leases			4,758,980				—
Investments in Oil & Gas properties			(1,961,329	)			(120,051	)
Investment in Non Oil and Gas assets			(21,810	)			(2,738	)
Net cash provided by investing activities			2,775,841				31,500
Cash flows from Financing Activities:
Proceeds from Promissory Notes			700,000				—
Payments on Promissory Notes			(700,000	)			(2,983	)
Net cash used by financing activities			—				(2,983	)
Effect of exchange rate on cash and equivalents			1,246				(78,152	)
Net increase/ (decrease) in cash and equivalents			2,577,566				(291,237	)
Cash and equivalents beginning of period			307,566				1,174,989
Cash and equivalents at end of period		$	2,885,132			$	883,752
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash Payment for Interest		$	100,000			$	71
Cash Payment for Income Taxes		$	—			$	—
Non-Cash Transactions:
Cancellation of shares for notes receivable		$	—			$	47,500

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 

OSAGE EXPLORATION AND DEVELOPMENT, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2011 (unaudited) and December 31, 2010

 

1. BASIS OF PRESENTATION

 

Osage Exploration and Development, Inc. (“Osage” or the “Company”) prepared the accompanying unaudited consolidated financial statements in accordance with accounting principles generally accepted in the United States of America (“United States”) for interim financial information and pursuant to the rules and Regulations of the Securities and Exchange Commission (“SEC”) instructions to Form 10-Q and Item 310(b) of regulation S-K. These financial statements should be read together with the financial statements and notes in the Company’s 2010 Form 10-K filed with the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles (“U.S. GAAP”) in the USA were condensed or omitted. The accompanying financial statements reflect all adjustments and disclosures, which, in the Company’s opinion, are necessary for fair presentation. All such adjustments are of a normal recurring nature. The results of operations for the interim periods are not necessarily indicative of the results of the entire year.

 

Going Concern

 

The Company incurred significant losses in the last three years and has an accumulated deficit of $7,525,775 at September 30, 2011 and $10,093,679 (audited) at December 31, 2010. Substantial portions of the losses are attributable to asset impairment charges, stock based compensation, professional fees and interest expense. The Company's operating plans require additional funds that may take the form of debt or equity financings. There is no assurance that additional funds will be available. The Company's ability to continue as a going concern is in substantial doubt and is dependent upon achieving a profitable level of operations and obtaining additional financing.

 

Management of our Company has undertaken steps as part of a plan to improve operations with the goal of sustaining our operations for the next twelve months and beyond. These steps include (a) assigning a portion of our oil and gas leases in Logan County, Oklahoma (b) participating in drilling of wells in Logan County, Oklahoma within the next twelve months, (c) controlling overhead and expenses and (d) raising additional capital and/or obtaining financing.

 

There is no assurance the Company can accomplish these steps and it is uncertain the Company will achieve profitable operations and obtain additional financing. There is no assurance that additional financings will be available to the Company on satisfactory terms and conditions, if at all. In the event we are unable to continue as a going concern, we may elect or be required to seek protection from our creditors by filing a voluntary petition in bankruptcy or may be subject to an involuntary petition in bankruptcy. To date, management has not considered this alternative, nor does management view it as a likely occurrence.

 

These consolidated financial statements do not give effect to any adjustments which would be necessary should the Company be unable to continue as a going concern and therefore be required to realize its assets and discharge its liabilities in other than the normal course of business and at amounts different from those reflected in the accompanying consolidated financial statements.

 

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 

Basis of Consolidation

 

The consolidated financial statements include the accounts of Osage and its wholly owned subsidiaries, Osage Energy Company, LLC and Cimarrona, LLC. Accordingly, all references herein to Osage or the Company include the consolidated results. All significant inter-company accounts and transactions were eliminated in consolidation.

 

 

Use of Estimates

 

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

 

Osage’s consolidated financial statements are based on a number of significant estimates, including oil and gas reserve quantities which are the basis for the calculation of depreciation, depletion and impairment of oil and gas properties, as well as the cost and timing of its asset retirement obligations.

 

Cash and Equivalents

 

Cash and equivalents include cash in banks and financial instruments which mature within three months of the date of purchase.

 

Concentration of Credit Risk

 

Financial instruments that potentially subject the Company to concentration of credit risk consist of cash and accounts receivable. Cash balances exceeded FDIC insurance protection levels by $2,005,077 at September 30, 2011, and at certain points throughout the year, subjecting the Company to risk related to the uninsured balance. The Company’s deposits are held at large established bank institutions and it believes that the risk of loss associated with these uninsured balances is remote.

 

Accounts receivable are recorded at invoiced amount and generally do not bear interest. Any allowance for doubtful accounts is based on management's estimate of the amount of probable losses due to the inability to collect from customers and working interest owners.

 

Sales to one customer comprised approximately 55% of Osage’s total revenues for the three and nine months ended September 30, 2011. In the three and nine months ended September 30, 2010 this same customer accounted for approximately 75% and 78% of total revenues, respectively. Osage believes that, in the event that its primary customer was unable or unwilling to continue to purchase Osage’s production, there are a substantial number of alternative buyers for its production at comparable prices.

 

Fair Value of Financial Instruments

 

As of September 30, 2011 and December 31, 2010, the fair value of cash, accounts receivable and accounts payable approximate carrying values because of the short-term maturity of these instruments.

 

Property, Plant and Equipment

 

Property, plant and equipment are stated at cost and consist primarily of furniture and office equipment. Depreciation is computed on a straight-line basis over the estimated useful lives of three to five years.

 

Revenue Recognition

 

We recognize sales from one of our properties using the sales method. Under the sales method, the working interest owners recognize sales of oil and gas regardless of the amount produced for the period. The sales method assumes that any production sold by a working interest owner comes from that party’s share of the total reserves in place. Thus, whatever quantity is sold in any given period is the revenue for that party. No receivables, payables or unearned revenue are recorded unless a working interest owner’s aggregate sales from the property exceed its share of the total reserves in place. If such a situation arises, the parties would likely choose to cash balance or in some instances, the over delivered partner might choose to negotiate to buy out the under delivered party’s share. For the nine months ending September 30, 2011, we recognized sales of $1,262 and 13 barrels in excess of production. For the year ending December 31, 2010, we recognized sales of $108,918 and 1,344 barrels in excess of production. At September 30, 2011, the company’s share of reserves exceeded 200,596 barrels.

 

  

Recent Accounting Pronouncements

  

There were various accounting standards and interpretations issued recently, none of which are expected to a have a material impact on our consolidated financial position, operations or cash flows.

 

All new accounting pronouncements issued but not yet effective have been deemed to not be applicable, hence the adoption of these new standards is not expected to have a material impact on the consolidated financial statements.

 

Subsequent Events

 

Osage evaluated all transactions from September 30, 2011 through the financial statement issuance date for subsequent event disclosure.

 

Income Tax

 

The Company follows FASB ASC topic 740 (“ASC 740”) “Accounting for Uncertainty in Income Taxes.” As a result of the implementation of ASC 740, the Company made a comprehensive review of its portfolio of tax positions in accordance with recognition standards established by ASC 740. As a result of the implementation of ASC 740, the Company recognized no material adjustments to liabilities or stockholders equity.

 

When tax returns are filed, it is likely that some positions taken would be sustained upon examination by the taxing authorities, while others are subject to uncertainty about the merits of the position taken or the amount of the position that would be ultimately sustained. The benefit of a tax position is recognized in the financial statements in the period during which, based on all available evidence, management believes it is more likely than not that the position will be sustained upon examination, including the resolution of appeals or litigation processes, if any. Tax positions taken are not offset or aggregated with other positions. Tax positions that meet the more-likely-than-not recognition threshold are measured as the largest amount of tax benefit that is more than 50 percent likely of being realized upon settlement with the applicable taxing authority. The portion of the benefits associated with tax positions taken that exceeds the amount measured as described above is reflected as a liability for unrecognized tax benefits in the accompanying balance sheets along with any associated interest and penalties that would be payable to the taxing authorities upon examination.

 

Interest associated with unrecognized tax benefits are classified as interest expense and penalties are classified in selling, general and administrative expenses in the Consolidated Statement of Operations.

 

The Company did not have a provision for income taxes for 2011 or 2010. Due to a history of operating losses, the Company records a full valuation allowance against its net deferred tax assets and therefore recorded no tax provision related to its U.S. operations for the current period.

 

2. OIL AND GAS PROPERTIES

 

Oil and gas properties consisted of the following as of September 30, 2011 (unaudited) and December 31, 2010 (audited):

 

		2011				2010
Properties subject to amortization		$	2,216,669			$	2,225,369
Properties not subject to amortization			902,727				593,464
Capitalized asset retirement costs			46,146				46,146
			3,165,542				2,864,979
Accumulated depreciation and depletion			(1,191,956	)			(897,833	)
Oil & Gas Properties, Net		$	1,973,586			$	1,967,146

 

 

On April 21, 2011, we entered into a participation agreement (“Participation Agreement”) with Slawson Exploration Company (“Slawson”) and U.S. Energy Development Corporation (”USE”, Slawson and USE, together, the “Parties”). Pursuant to the terms of the Participation Agreement, Slawson and USE acquired 45% and 30% respectively, of our 10,000 acre Nemaha Ridge prospect in Logan County, OK for $4,875,000. In addition, the Parties shall carry Osage for 10% of the cost of the first three horizontal Mississippian wells. Revenue from wells drilled pursuant to the Participation Agreement shall be allocated 45% to Slawson, 30% to USE and 25% to Osage. Slawson will be the operator of all wells in the Nemaha Ridge prospect. In the quarter ending September 30, 2001, Slawson and USE acquired 45% and 30%, respectively, of an additional 3,388 acres that we offered to them. We are continuing to acquire additional acreage in the Nemaha Ridge prospect and we will offer the additional acreage to the Parties, at our cost, subject to their acceptance.

 

3. GEOGRAPHICAL INFORMATION

 

The following table sets forth revenues for the periods reported and assets by geographic location:

 

		Revenues for the								Revenues for the
		Three Months ended September 30, 2011								Three Months ended September 30, 2010
		Amount				% of Total				Amount				% of Total
Colombia		$	844,128				98.8	%		$	443,253				94.7	%
United States			10,072				1.2	%			24,694				5.3	%
Total		$	854,200				100.0	%		$	467,947				100.0	%

 

		Revenues for the								Revenues for the
		Nine Months ended September 30, 2011								Nine Months ended September 30, 2010
		Amount				% of Total				Amount				% of Total
Colombia		$	2,427,250				98.7	%		$	1,188,620				93.8	%
United States			31,144				1.3	%			78,438				6.2	%
Total		$	2,458,394				100.0	%		$	1,267,058				100.0	%

 

		Long Lived Assets at								Long Lived Assets at
		September 30, 2011								December 31, 2010
Colombia		$	2,098,696				64.7	%		$	2,104,396				72.1	%
United States			1,143,517				35.3	%			815,444				27.9	%
Total		$	3,242,213				100.0	%		$	2,919,840				100.0	%

 

4. PROMISSORY NOTES

 

On April 27, 2007, we purchased a truck to be used by our pumper in our Osage, Oklahoma property by issuing a promissory note (the “Promissory Note”) to a bank secured by the truck. The Promissory Note had a variable interest rate of Prime plus 1.0% and monthly principal and interest payments totaling $366. The Promissory Note matured and was paid off on October 27, 2010.

 

On January 24, 2011, we issued a secured promissory note to an institutional investor (“Blackrock Note”) for $500,000. The Blackrock Note matured May 24, 2011, had a loan fee of $100,000, payable at the time of repayment, and was secured by an assignment of all of our current and future leases in Logan County, OK and our ownership in Cimarrona LLC. The Company repaid the Blackrock Note and the loan fee on May 24, 2011 with the proceeds of the Participation Agreement.

 

 

On April 5, 2011, we issued a secured promissory note (“Secured Promissory Note”) to Peter Hoffman (“Hoffman”), an individual investor for $200,000. The Secured Promissory Note matured August 5, 2011, had a loan fee and prepaid interest of 250,000 shares of common stock, $0.0001 par value, valued at $35,000, and was secured by an assignment of the Company’s future oil and gas leases in Logan County, OK. The Company repaid the Secured Promissory Note on May 24, 2011 with the proceeds of the Participation Agreement. Hoffman owns approximately 13.2% of the Company. The Secured Promissory Note was entered into through arms-length negotiations.

 

5. COMMITMENTS AND CONTINGENCIES

 

ENVIRONMENT

 

Osage, as owner and operator of oil and gas properties, is subject to various federal, state, and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the owner of real property and the lessee under oil and gas leases for the cost of pollution clean-up resulting from operations, subject the owner/lessee to liability for pollution damages and impose restrictions on the injection of liquids into subsurface strata.

 

Although the Company’s environmental policies and practices are designed to ensure compliance with these laws and regulations, future developments and increasing stringent regulations could require the Company to make additional unforeseen environmental expenditures

 

The Company maintains insurance coverage it believes is customary in the industry, although it is not fully insured against all environmental risks.

 

The Company is not aware of any environmental claims existing as of September 30, 2011, that would have a material impact on its consolidated financial position or results of operations. There can be no assurance, however, that current regulatory requirements will not change, or past non-compliance with environmental laws will not be discovered on the Company's property.

 

LAND RENTALS AND OPERATING LEASES

 

In February 2008, the Company entered into a 36 month lease for its corporate offices in San Diego. The lease, including parking, was initially for $3,682 per month for the first year, increasing to $3,800 and $3,923 in the second and third year respectively. The lease was guaranteed by Mr. Bradford, our President, CEO and CFO. No compensation was given to Mr. Bradford for his guarantee. In addition, the Company is responsible for all operating expenses and utilities.

 

In February 2011, the Company amended the lease for another three years, with initial payments, including parking of $3,488 per month for the first year, increasing to $3,599 and $3,715 in the second and third year, respectively. The amended lease released Mr. Bradford of his guarantee, but required the Company to increase its security deposit from $3,381 to $10,000, with $3,299 and $3,415 of the security deposit to be applied to months 13 and 25, respectively, of the lease. Outside of the San Diego lease, the Company’s Oklahoma office and all equipment leased are under month-to-month operating leases.

 

Future minimum rental payments required as of September 30, 2011 under operating leases are as follows by year:

 

			Amount
2012		$	39,335
2013			40,586
2014			18,574
Total		$	98,495

 

 

Rental expense totaled $13,163 and $40,263 for the three and nine months ended September 30, 2011, respectively. Rental expense totaled $14,400 and $41,555 for the three and nine months ended September 30, 2010, respectively.

 

LEGAL PROCEEDINGS

 

Except as set forth below, the Company is not a party to any litigation, other than ordinary routine litigation that has arisen in the normal course of its business and that of its subsidiaries.

 

In the quarter ending March 31, 2010, the Company recorded a charge of 1,675,235,000 Colombian Pesos ($860,937) as, in the first quarter of 2010, we were notified by Division de Impuestos y Actuanas Nacionales (“DIAN”), the Colombian tax authorities, that Cimarrona owes this amount for taxes assessed on its equity value relating to its operations in 2001 and 2003 prior to its ownership by us. In order to compute the equity value the equity tax is assessed upon, Cimarrona subtracted the cost of its non-producing wells in 2001 and 2003. However, DIAN’s position is that as long as the field is productive, Cimarrona should not have subtracted the cost of the non-producing wells. In May 2011, we settled in full the 2001 liability with DIAN and paid 613,772,000 Colombian Pesos ($345,341). DIAN has indicated that it now believes the 2003 tax amount should be 1,627,552,000 Colombian Pesos ($915,749) and the Company therefore recorded a charge in the quarter ending June 30, 2011 of 563,089,000 Colombian Pesos ($310,297). The Company is currently appealing DIAN’s decision on the 2003 equity tax, but in the event the Company loses its appeal, it believes it may need to begin paying the 2003 taxes by the beginning of 2012. The Company believes that, in the event it loses its appeal, it may be able to make these tax payments over a three to seven year period.

 

6. MAJOR CUSTOMERS

 

In the three months ended September 30, 2011 and 2010 and in the nine months ended September 30, 2010, three customers accounted for all of the Company’s sales. In the nine months ended September 30, 2011, four customers accounted for all of the Company’s sales.

  

		Three Months ended								Three Months ended
		September 30, 2011								September 30, 2010
		Amount				% of Total				Amount				% of Total
HOCOL		$	371,987				43.5	%		$	351,861				75.2	%
Pacific			472,141				55.3	%			91,392				19.5	%
Coffeyville			10,072				1.2	%			—				0.0	%
Sunoco			—				0.0	%			24,694				5.3	%
Total		$	854,200				100.0	%		$	467,947				100.0	%

 

		Nine Months ended								Nine Months ended
		September 30, 2011								September 30, 2010
		Amount				% of Total				Amount				% of Total
HOCOL		$	1,364,048				55.5	%		$	989,935				78.1	%
Pacific			1,063,202				43.2	%			198,685				15.7	%
Coffeyville			10,072				0.4	%			—				0.0	%
Sunoco			21,072				0.9	%			78,438				6.2	%
Total		$	2,458,394				100.0	%		$	1,267,058				100.0	%

 

  

7. ASSET RETIREMENT OBLIGATIONS

 

The Company recognizes a liability at discounted fair value for the future retirement of tangible long-lived assets and associated assets retirement cost associated with the petroleum and natural gas properties. The fair value of the liability is capitalized as part of the cost of the related asset and amortized to expense over its useful life. The liability accretes until the date of expected settlement of the retirement obligations. The related accretion expense is recognized in the statement of operations. The provision will be revised for the effect of any changes to timing related to cash flow or undiscounted abandonment costs. Actual expenditures incurred for the purpose of site reclamation are charged to the asset retirement obligations to the extent that the liability exists on the balance sheet. Differences between the actual costs incurred and the fair value of the liability recorded are recognized in income in the period the actual costs are incurred.

 

There are no legally restricted assets for the settlement of asset retirement obligations. A reconciliation of the Company's asset retirement obligations for the periods presented is as follows:

 

		September 30, 2011												December 31, 2010
		Colombia				United States				Combined				Colombia				United States				Combined
Beginning Balance		$	35,719			$	22,027			$	57,746			$	35,719			$	20,023			$	55,742
Accretion expense			—				1,653				1,653				—				2,004				2,004
Ending Balance		$	35,719			$	23,680			$	59,399			$	35,719			$	22,027			$	57,746

 

8. CHANGE IN EQUITY

 

During the nine months ended September 30, 2011, the Company issued 1,150,000 shares, valued at $285,000. 900,000 shares, valued at $250,000 were issued to three consultants and were charged to operating expenses, while 250,000 shares, valued at $35,000 were issued as a loan fee and prepaid interest pursuant to the Secured Promissory Note, as more fully described in footnote 5 above. During the 3 months ended September 30, 2011, the Company issued 500,000 shares, valued $150,00 to one consultant. The shares were valued based upon the closing stock price at the date of issuance.

 

Item 2.

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

 

This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 that include, among others, statements of: expectations, anticipations, beliefs, estimations, projections, and other similar matters that are not historical facts, including such matters as: future capital requirements, development and exploration expenditures (including the amount and nature thereof), drilling of wells, reserve estimates (including estimates of future net revenues associated with such reserves and the present value of such future net revenues), future production of oil and gas, repayment of debt, business strategies, and expansion and growth of business operations. These statements are based on certain assumptions and analyses made by our management in light of past experience and perception of: historical trends, current conditions, expected future developments, and other factors that our management believes are appropriate under the circumstances. We caution the reader that these forward-looking statements are subject to risks and uncertainties, including those associated with the financial environment, the regulatory environment, and trend projections, that could cause actual events or results to differ materially from those expressed or implied by the statements. Such risks and uncertainties include those risks and uncertainties identified below.

 

Significant factors that could prevent us from achieving our stated goals include: declines in the market prices for oil and gas, adverse changes in the regulatory environment affecting us, the inherent risks involved in the evaluation of properties targeted for acquisition, our dependence on key personnel, the availability of capital resources at terms acceptable to us, the uncertainty of estimates of proved reserves and future net cash flows, the risk and related cost of replacing produced reserves, the high risk in exploratory drilling and competition. You should consider the cautionary statements contained or referred to in this report in connection with any subsequent written or oral forward-looking statements that may be issued. We undertake no obligation to release publicly any revisions to any forward-looking statement to reflect events or circumstances after the date hereof or to reflect the occurrence of unanticipated events.

 

 

On April 8, 2008, we entered into a membership interest purchase agreement (the “Purchase Agreement”) with Sunstone Corporation (“Sunstone”) pursuant to which we acquired from Sunstone 100% of the membership interests in Cimarrona Limited Liability Company, an Oklahoma limited liability company (“Cimarrona LLC”). Cimarrona LLC is the owner of a 9.4% interest in certain oil and gas assets in the Guaduas field, located in the Dindal and Rio Seco Blocks that consist of twenty one wells, of which seven are currently producing, that covers 30,665 acres in the Middle Magdalena Valley in Colombia as well as a pipeline with a current capacity of approximately 30,000 barrels of oil per day. The Purchase Agreement was effective as of April 1, 2008.

 

The Cimarrona property is subject to an Ecopetrol Association Contract (the “Association Contract”) whereby we pay Ecopetrol S.A. (“Ecopetrol”) royalties of 20% of the oil produced. The pipeline is not subject to the Association Contract. The royalty amount for the Cimarrona property is paid in oil. In addition to the royalty, according to the Association Contract, Ecopetrol may, for no consideration, become a 50% partner, once an audit of revenues and expenses indicate that the partners in the Association Contract have a received a 200% reimbursement of all historical costs to develop and operate the Guaduas field. We believe that Ecopetrol could become a 50% partner in 2012, which would effectively reduce our cash flows by 50%. In addition, in 2022, the Association Contract with Ecopetrol terminates, at which time we will have no economic interest remaining in this property. The property and the pipeline are both operated by Pacific, which owns 90.6% of the Guaduas field. Pipeline revenues generated from Cimarrona primarily relate to transportation costs charged to third party oil producers, including Pacific.

 

In 2010, we began to acquire oil and gas leases in Logan County, Oklahoma targeting the Mississippian formation. The Mississippian formation is located on the Anadarko Shelf in northern Oklahoma and south-central Kansas. The top of this expansive carbonate hydrocarbon system is encountered between 4,000 and 6,000 feet and lies stratigraphically between the Pennsylvanian-aged Morrow Sand and the Devonian-aged Woodford Shale formations. The Mississippian formation may reach 600 feet in gross thickness and the targeted porosity zone is between 50 and 300 feet in thickness. The formation’s geology is well understood as a result of the thousands of vertical wells drilled and produced there since the 1940s. Beginning in 2007, the application of horizontal cased-hole drilling and multi-stage hydraulic fracturing treatments have demonstrated the potential for extracting significant additional quantities of oil and natural gas from the formation.

 

On April 21, 2011, we entered into the Participation Agreement with Slawson and USE. Pursuant to the terms of the Participation Agreement, Slawson and USE acquired 45% and 30% respectively, of our 10,000 acre Nemaha Ridge prospect located in Logan County, OK for $4,875,000. In addition, Slawson and USE shall carry Osage for 10% of the cost of the first three horizontal Mississippian wells. Revenue from wells drilled pursuant to the Participation Agreement shall be allocated 45% to Slawson, 30% to USE and 25% to Osage. Slawson will be the operator of all wells in the Nemaha Ridge prospect. In the quarter ending September 30, 2001, Slawson and USE acquired 45% and 30%, respectively, of an additional 3,388 acres that we offered to them. We are continuing to acquire additional acreage in the Nemaha Ridge prospect and we will offer the additional acreage to Slawson and USE, at our cost, subject to their acceptance.

 

We anticipate we will need to raise at least $2,000,000 to provide for requirements for the next twelve months to be used primarily for our share of drilling costs in the Nemaha Ridge Prospect. At present, the revenues generated from our properties are only sufficient to cover field operating expenses and a portion of our overhead.

 

We have undertaken steps as part of a plan to improve operations with the goal of sustaining our operations for the next twelve months and beyond. These steps include (a) assigning a portion of our oil and gas leases in Logan County, Oklahoma (b) participating in drilling of wells in Logan County, Oklahoma within the next twelve months, (c) controlling overhead and expenses and (d) raising additional capital and/or obtaining financing.

 

There is no assurance we will successfully accomplish these steps and it is uncertain we will achieve a profitable level of operations and/or obtain additional financing. There can be no assurance that any additional financings will be available to us on satisfactory terms and conditions, if at all. In the event we are unable to continue as a going concern, we may elect or be required to seek protection from our creditors by filing a voluntary petition in bankruptcy or may be subject to an involuntary petition in bankruptcy. To date, management has not considered this alternative, nor does management view it as a likely occurrence.

 

 

Results of Operations

 

Three Months ended September 30, 2011 compared to Three Months ended September 30, 2010

 

		2011								2010								Change
		Amount				Percentage				Amount				Percentage				Amount				Percentage
Oil Sales		$	382,059				44.7	%		$	376,555				80.5	%		$	5,504				1.5	%
Pipeline Sales			472,141				55.3	%			91,392				19.5	%			380,749				416.6	%
Total Revenues		$	854,200				100.0	%		$	467,947				100.0	%		$	386,253				82.5	%

 

Oil Sales

 

Oil Sales for the three months ended September 30, 2011 were $382,059, an increase of $5,504, or 1.5%, compared to $376,655 for the three months ended September 30, 3010. The increase is due primarily to an increase in oil prices, offset by a decrease in barrels (“BBLs”) sold. In Colombia, we sold 4,000 BBLs at an average gross price of $96.37 per barrel in the three months ended September 30, 2011 compared to 5,000 BBLs at an average gross price of $72.92 for the three months ended September 30, 2010. In the United States, we sold 161BBLs at an average gross price of $82.73 for the three months ended September 30, 2011 compared to 467 BBLs at an average gross price of $71.90 for the three months ended September 30, 2010.

 

Pipeline Sales

 

The Guaduas pipeline connects with the ODC pipeline (the “ODC Pipeline”) to transport oil to the port of Covenas in Colombia. Pipeline sales were $472,141 in the three months ended September 30, 2011, an increase of $380,749, or 416.6% compared to $91,392 in the three months ended September 30, 2010. In the three months ended September 30, 2011, the pipeline transported 2.69 million BBls (our share was approximately 253,000 BBLs) compared to 0.95 million BBls (our share was approximately 89,000 BBLs) in the three months ended September 30, 2010

 

Total revenues were $854,200 for the three months ended September 30, 2011, an increase of $386,253, or 82.5%, compared to $467,947 for the three months ended September 30, 2010. Pipeline sales accounted for 55.3% and 19.5% of total revenues in the three months ended September 30, 2011 and 2010, respectively.

 

Production

 

		2011								2010								Increase/(Decrease)
		Net Barrels				% of Total				Net Barrels				% of Total				Barrels				%
Colombia			4,605				96.6	%			4,220				90.0	%			385				9.1	%
United States			161				3.4	%			467				10.0	%			(306	)			(65.5	)%
Total			4,766				100.0	%			4,687				100.0	%			79				1.7	%

 

Production, net of royalties for the three months ended September 30, 2011 was 4,766 BBLs, an increase of 79 BBLs, or 1.7%, compared to 4,687 BBLs for the three months ended September 30, 2010. Colombian production increased by 385 BBLs, while production in the United States decreased by 306 BBls. Colombian production accounted for 96.6% and 90.0% of total production in the three months ended September 30, 2011 and 2010, respectively.

 

 

Operating Costs and Expenses

 

		2011								2010								Change
						Percent of								Percent of								Percent of
		Amount				Sales				Amount				Sales				Amount				Sales
Operating Expenses
Operating		$	283,201				33.2	%		$	169,644				36.3	%		$	113,557				66.9	%
General & Administrative			419,263				49.1	%			354,258				75.7	%			65,005				18.3	%
Equity Tax			35,483				3.5	%			75,619				16.2	%			(40,136	)			(53.1	)%
Depreciation , Depletion and Accretion			112,900				13.2	%			89,995				19.2	%			22,905				25.5	%
Stock Based Compensation			150,000				17.6	%			39,300				8.4	%			110,700				281.6	%
Total Operating Expenses		$	1,000,847				117.2	%		$	728,816				155.7	%		$	272,031				37.3	%

 

Operating Expenses

 

Our operating expenses were $283,201 in the three months ended September 30, 2011 compared to $169,644 in the three months ended September 30, 2010, due primarily to an increase in operating costs in both Colombia and Oklahoma. Operating expenses as a percentage of total revenues decreased to 33.2% in the three months ended September 30, 2011 from 36.3% in the three months ended September 30, 2010 as the increase in revenues exceeded the increase in operating expenses.

 

The Company’s average production cost per barrel for the three months ended September 30, 2011 and September 30, 2010 is as follows:

 

		2011												2010
		USA				Colombia				Total				USA				Colombia				Total
Average Production per Barrel		$	219.76			$	25.27			$	30.56			$	58.08			$	20.30			$	23.37

 

General and Administrative Expenses

 

General and administrative expenses were $419,263 in the three months ended September 30, 2011, an increase of $65,005 or 18.3%, compared to $354,258 in the three months ended September 30, 2010. The increase is due primarily to increased professional fees. As a percent of total revenues, general and administrative expenses decreased from 75.7% in the three months ended September 30, 2010 to 49.1% in the three months ended September 30, 2011 as the increase in revenues exceeded the increase in general and administrative expenses.

 

Equity Tax

 

Division de Impuestos y Actuanas Nacionales (“DIAN”), the Colombian tax authorities, levies a tax based on the equity value of Cimarrona. Equity tax was $35,483 in the three months ended September 30, 2011, a decrease of $40,136 or 53.1%, compared to $75,619 in the three months ended September 30, 2010.

 

Depreciation, depletion and accretion

 

Depreciation, depletion and accretion were $112,900 in the three months ended September 30, 2011 and $89,995 in the three months ended September 30, 2010. The increase is primarily due to increased Colombian oil production.

 

Stock Based Compensation Expense

 

Stock based compensation expense was $150,000 in the three months ended September 30, 2011 compared to $39,300 in the three months ended September 30, 2010. Stock based compensation expense for the three months ended September 30, 2011 resulted from the issuance of 500,000 shares for services to a consultant, while stock based compensation expense for the three months ended September 30, 2010 resulted from the issuance of 2,400,000 shares to an officer, a new board member and a consultant. The shares were valued based upon the closing stock price at the date of issuance.

 

 

Loss from Operations

 

Loss from operations was $146,647 and $260,869 in the three months ended September 30, 2011 and 2010, respectively. Loss from operations improved $114,222 as revenues increased by $386,253 while operating expenses increased by $272,031.

 

Interest Expense

 

Interest expense was $551 and $513 in the three months ended September 30, 2011 and 2010, respectively.

 

Interest Income

 

Interest Income was $4,411 and $546 in the three months ended September 30, 2011 and 2010, respectively. The increase in interest income is primarily due to higher cash balances in the three months ended September 30, 2011 resulting from the assignment of oil and gas leases in Logan County, Oklahoma pursuant to the Participation Agreement.

 

Provision for Income Taxes

 

Provision for income taxes was zero in the three months ended September 30, 2011 and 2010. Due to a history of operating losses, the Company records a full valuation allowance against its net deferred tax assets and therefore recorded no tax provision related to its U.S. operations for the current period.

 

Net Loss

 

Net loss was $142,787 in the three months ended September 30, 2011 compared to a net loss of $260,836 in the three months ended September 30, 2010.

 

Foreign Currency Translation Gain

 

Foreign currency translation gain was $17,861 in the three months ended September 30, 2011 compared to a foreign currency translation gain of $75,015 in the three months ended September 30, 2010. The Colombian Peso to Dollar Exchange Rate averaged 1,793 and 1,833 for the three months ended September 30, 2011 and 2010, respectively and was 1,934 and 1,803 at September 30, 2011 and September 30, 2010, respectively.

 

Comprehensive Loss

 

Comprehensive loss was $124,926 in the three months ended September 30, 2011 compared to a comprehensive loss of $185,821 in the three months ended September 30, 2010. The $60,895 improvement is due to the $118,049 improvement in net loss, offset by a $57,154 decrease in the foreign currency translation gain.

 

 

Results of Operations

 

Nine Months ended September 30, 2011 compared to Nine Months ended September 30, 2010

 

		2011								2010								Change
		Amount				Percentage				Amount				Percentage				Amount				Percentage
Oil Sales		$	1,395,192				56.8	%		$	1,068,373				84.3	%		$	326,819				30.6	%
Pipeline Sales			1,063,202				43.2	%			198,685				15.7	%			864,517				435.1	%
Total Revenues		$	2,458,394				100.0	%		$	1,267,058				100.0	%		$	1,191,336				94.0	%

 

Oil Sales

 

Oil Sales for the nine months ended September 30, 2011 were $1,359,192, an increase of $326,819, or 30.6%, compared to $1,068,373 in the nine months ended September 30, 2010. The increase is due primarily to an increase in oil prices, offset by a decrease in BBLs sold in the United States. In Colombia, we sold 14,000 BBLs in the nine months ended September 30, 2011 at an average gross price of $100.96 per barrel compared to 14,000 BBLs at an average gross price of $73.27 in the nine months ended September 30, 2010. In the United States, we sold 470 BBLs at an average gross price of $87.92 in the nine months ended September 30, 2011 compared to 1,442 BBLs at an average gross price of $72.13 in the nine months ended September 30, 2010.

 

Pipeline Sales

 

Pipeline sales for the nine months ended September 30, 2011 were $1,063,202, an increase of $864,517, or 435.1%, compared to $198,685 in the nine months ended September 30, 2010. In the nine months ended September 30, 2011, the pipeline transported 6.20 million BBls (our share was approximately 587,000 BBLs) compared to 1.23 million BBls (our share was approximately 116,000 BBLs) in the nine months ended September 30, 2010.

 

Total revenues for the nine months ended September 30, 2011 were $2,458,394, an increase of $1,191,306, or 94.0%, compared to $1,267,058 in the nine months ended September 30, 2010. Oil sales accounted for 56.8% and 84.3% of total revenues in the nine months ended September 30, 2011 and 2010, respectively.

 

Production

 

		2011								2010								Increase/(Decrease)
		Net Barrels				% of Total				Net Barrels				% of Total				Barrels				%
Colombia			13,987				96.7	%			13,748				90.5	%			239				1.7	%
United States			470				3.3	%			1,442				9.5	%			(972	)			(67.4	)%
Total			14,457				100.0	%			15,190				100.0	%			(733	)			(4.8	)%

 

Production for the nine months ended September 30, 2011, net of royalties, was 14,457 BBLs, a decrease of 733 BBLs, or 4.8%, compared to 15,190 BBLs in the nine months ended September 30, 2010. Colombian production accounted for 96.7% and 90.5% of total production in the nine months ended September 30, 2011 and 2010, respectively.

 

 

Operating Costs and Expenses

 

		2011								2010								Change
						Percent of								Percent of								Percent of
		Amount				Sales				Amount				Sales				Amount				Sales
Operating Expenses
Operating		$	702,378				28.6	%		$	458,657				36.2	%		$	243,721				53.1	%
General & Administrative			1,188,643				48.4	%			1,054,655				83.2	%			133,988				12.7	%
Equity Tax			405,935				14.1	%			1,007,567				35.6	%			(601,632	)			(59.7	)%
Depreciation , Depletion and Accretion			322,607				13.1	%			267,402				21.1	%			55,205				20.6	%
Stock Based Compensation			250,000				10.2	%			39,300				3.1	%			210,700				536.1	%
Total Operating Expenses		$	2,869,563				116.7	%		$	2,827,581				223.2	%		$	41,982				1.5	%

 

  

Operating Expenses

 

Our operating expenses were $702,378 in the nine months ended September 30, 2011 compared to $458,657 in the nine months ended September 30, 2010, due primarily to an increase in operating costs in Colombia and Oklahoma. Operating expenses as a percentage of total revenues decreased to 28.6% in the nine months ended Septebmer 30, 2011 from 36.2% in the nine months ended September 30, 2010 as the increase in revenues was much greater than the increase in operating expenses.

 

The Company’s average production cost per barrel for the nine months ended September 30, 2011 and 2010 was as follows:

 

		2011												2010
		USA				Colombia				Total				USA				Colombia				Total
Average Production per Barrel		$	167.31			$	33.18			$	36.69			$	49.10			$	21.26			$	23.41

 

  

General and Administrative Expenses

 

General and administrative expenses were $1,188,643 in the nine months ended September 30, 2011, an increase of $133,988 or 12.7%, compared to $1,054,655 in the nine months ended September 30, 2010. The increase is due primarily increased professional fees, travel and printing expenses. As a percent of total revenues, general and administrative expenses decreased from 83.2% in the nine months ended September 30, 2010 to 48.4% in the nine months ended September 30, 2011 as the increase in revenues was greater than the increase in general and administrative expenses.

 

Equity Tax

 

Equity tax was $405,935 in the nine months ended September 30, 2011, a decrease of $601,632 or 59.7%, compared to $1,007,567 in the nine months ended September 30, 2010. In the three months ended March 31, 2010, the Company recorded an equity tax expense of 1,675,235,000 Colombian Pesos ($860,937) as, in the first quarter of 2010, we were notified by the DIAN, that Cimarrona owes this amount for taxes assessed on its equity value relating to its operations in 2001 and 2003 prior to its ownership by us. In order to compute the equity value the equity tax is assessed upon, Cimarrona subtracted the cost of its non-producing wells in 2001 and 2003. However, DIAN’s position is that as long as the field is productive, Cimarrona should not have subtracted the cost of the non-producing wells. In May 2011, we settled in full the 2001 liability with DIAN and paid 613,772,000 Colombian Pesos ($345,341). DIAN has indicated that it now believes the 2003 tax amount should be 1,627,552,000 Colombian Pesos ($915,749) and the Company therefore recorded an expense in the quarter ending June 30, 2011 of 563,089,000 Colombian Pesos ($310,297). The Company is currently appealing DIAN’s decision on the 2003 equity tax, but in the event the Company loses its appeal, it believes it may need to begin paying the 2003 taxes by the beginning of 2012. The Company believes that, in the event it loses its appeal, it may be able to make these tax payments over a three to seven year period.

 

 

Depreciation, depletion and accretion

 

Depreciation, depletion and accretion were $322,607 in the nine months ended September 30, 2011 and $267,402 in the nine months ended September 30, 2010. The increase is primarily due to increased Colombian oil production.

 

Stock Based Compensation Expense

 

Stock based compensation expense was $250,000 in the nine months ended September 30, 2011 compared to $39,300 in the nine months ended September 30, 2010. Stock based compensation expense for the nine months ended September 30, 2011 resulted from the issuance of 900,000 shares to three consultants, while stock based compensation expense for the nine months ended September 30, 2010 resulted from the issuance of 2,400,000 shares to an officer, a new board member and a consultant. The shares were valued based upon the closing stock price at the date of issuance.

 

Loss from Operations

 

Loss from operations was $411,169 and $1,560,523 in the nine months ended September 30, 2011 and 2010, respectively. Loss from operations improved $1,149,354 as revenues increased by $1,191,336, while operating expenses increased by only $41,982.

 

Interest Expense

 

Interest expense was $136,653 in the nine months ended September 30, 2011 compared to $1,574 in the nine months ended September 30, 2010, an increase of $135,079. $135,000 of the increase is related to the interest on the Blackrock Promissory Note and the value of the shares issued as loan fee and prepaid interest on the Secured Promissory Note.

 

Other Income

 

Other income totaled $3,115,726 in the nine months ended September 30, 2011 compared to $2,756 in the nine months ended September 30, 2010. The nine months ended September 30, 2011 included a gain of $3,109,646 from assignment of leases in Logan County, Oklahoma pursuant to the Participation Agreement as more fully described in footnote 2.

 

Provision for Income Taxes

 

Provision for income taxes was zero in the nine months ended September 30, 2011 and 2010. Due to a history of operating losses, the Company records a full valuation allowance against its net deferred tax assets and therefore recorded no tax provision related to its U.S. operations for the current period.

 

Net Income/(Loss)

 

Net income was $2,567,904 in the nine months ended September 30, 2011 compared to a net loss of $1,559,341 in the nine months ended September 30, 2010. The $4,127,245 improvement is due primarily to the $3,109,646 gain from assignment of leases and the $1,191,306 increase in revenues in the nine months ended September 30, 2011.

 

Foreign Currency Translation Gain

 

Foreign currency translation gain was $24,657 in the nine months ended September 30, 2011 compared to a foreign currency translation gain of $182,959 in the nine months ended September 30, 2010. The Colombian Peso to Dollar Exchange Rate averaged 1,823 and 1,911 for the nine months ended September 30, 2011 and 2010, respectively and was 1,934 and 1,803 at September 30, 2011 and September 30, 2010, respectively.

 

 

Comprehensive Income /(Loss)

 

Comprehensive income was $2,592,561 in the nine months ended September 30, 2011 compared to a comprehensive loss of $1,376,382 in the nine months ended September 30, 2010. The $3,968,943 improvement is due to the $4,151,902 improvement in net income, offset by the $158,302 decrease in foreign currency translation gain.

 

Liquidity and Capital Resources

 

We had working capital of $2,192,297 at September 30, 2011 compared to a working capital deficit of $653,503 at December 31, 2010. Working capital at September 30, 2011 consisted primarily of $2,885,132 of cash and equivalents and $295,878 of accounts receivable, offset by $870,308 of accrued expenses and $217,201 of accounts payable. Working capital deficit at December 31, 2010 consisted primarily of $872,308 accrued expenses and $202,880 of accounts payable, offset by $307,566 of cash and equivalents and $74,678 of accounts receivable.

 

Net cash used by operating activities totaled $199,521 in 2011 compared to net cash used by operating activities of $241,602 in 2010. The major components of the net cash used by operating activities in 2011 were the $3,109,646 gain on assignment of leases and the $220,357 increase in accounts receivable, offset by the $2,567,904 net income, $322,607 provision for depreciation and depletion and the $250,000 value of shares issued for services. The major components of the net cash used by operating activities in 2010 were the $1,559,341 net loss, offset by the $885,103 increase in accounts payable and accrued expenses and the $267,402 provision for depreciation and depletion.

 

Net cash provided by investing activities in 2011 totaled $2,775,841 and consisted primarily of $4,758,980 net proceeds from assignment of leases, offset by $1,961,329 investments in oil and gas properties. Net cash provided by investing activities in 2010 consisted primarily of $154,289 received from Pacific as reimbursement for previously capitalized pipeline expenditures, offset by $120,051 investment in oil and gas properties.

 

Net cash provided by financing activities totaled zero in 2011, consisting of $700,000 of proceeds from the Blackrock Note and the Secured Promissory Note, both of which were repaid in full in 2011. Net cash used by financing activities totaled $2,983 in 2010 and consisted entirely of payments made on the Promissory Note securing a truck.

 

Net operating revenues from our oil production are very sensitive to changes in the price of oil which makes it very difficult for management to predict whether or not we will be profitable in the future.

 

We conduct no product research and development. Any expected purchase of significant equipment is directly related to drilling operations and the completion of successful wells.

 

We operate our Osage County Property through independent contractors that operate producing wells for several small oil companies. Slawson is the operator of our Nemaha Ridge prospect in Logan County. Pacific Rubiales, owns 90.6% of the Guaduas field and is the operator of that field.

 

We are responsible for any contamination of land we own or lease. However, we carry pollution liability insurance policies, which may limit some potential contamination liabilities as well as claims for reimbursement from third parties.

 

Effect of Changes in Prices

  

Changes in prices during the past few years have been a significant factor in the oil and gas industry. The price received for the oil produced by us fluctuated significantly during the last year. Changes in the price that we receive for our oil and gas is set by market forces beyond our control as well as governmental intervention. The volatility and uncertainty in oil and gas prices have made it more difficult for a company like us to increase our oil and gas asset base and become a significant participant in the oil and gas industry. We currently sell all of our oil and gas production to Hocol in Colombia and Sunoco in the United States. However, in the event these customers discontinued oil and gas purchases, we believe we can replace these customers with other customers who would purchase the oil at terms standard in the industry.

 

 

We have no material exposure to interest rate changes. We are subject to changes in the price of oil and exchange rates of the Colombian Peso, which are out of our control. In our Cimarrona property in Colombia, we sold oil at prices ranging from $82.21 to $120.22 in 2011 compared to $63.32 to $78.70 per barrel in 2010. In our Osage property, we sold oil at prices ranging from $84.84 to $96.89 in 2011 compared to $68.61 to $77.15 per barrel in 2010. The Colombian Peso to Dollar Exchange Rate averaged 1,824 and 1,911 in 2011 and 2010, respectively. The Colombian Peso to Dollar Exchange Rate was 1,935 and 1,803 at September 30, 2011 and September 30, 2010, respectively.

 

Oil and Gas Properties

  

We follow the "successful efforts" method of accounting for our oil and gas exploration and development activities, as set forth in the Statement of Financial Accounting Standards (SFAS) No. 19 as amended, issued by the Financial Accounting Standards Board as codified by FASC ASC topic 932 (“ASC 932”). Under this method, we initially capitalize expenditures for oil and gas property acquisitions until they are either determined to be successful (capable of commercial production) or unsuccessful. The carrying value of all undeveloped oil and gas properties is evaluated periodically and reduced if such carrying value appears to have been impaired. Leasehold costs relating to successful oil and gas properties remain capitalized while leasehold costs which have been proven unsuccessful are charged to operations in the period the leasehold costs are proven unsuccessful. Costs of carrying and retaining unproved properties are expensed as incurred.

 

The costs of drilling and equipping development wells are capitalized, whether the wells are successful or unsuccessful. The costs of drilling and equipping exploratory wells are capitalized until they are determined to be either successful or unsuccessful. If the wells are successful, the costs of the wells remain capitalized. If, however, the wells are unsuccessful, the capitalized costs of drilling the wells, net of any salvage value, are charged to operations in the period the wells are determined to be unsuccessful. We did not record any impairment charges in 2011 or 2010.

 

The provision for depreciation and depletion of oil and gas properties is computed on the unit-of-production method. Under this method, we compute the provision by multiplying the total unamortized costs of oil and gas properties including future development, site restoration, and dismantlement abandonment costs, but excluding costs of unproved properties by an overall rate determined by dividing the physical units of oil and gas produced during the period by the total estimated units of proved oil and gas reserves. This calculation is done on a country-by-country basis. As of September 30, 2011, our oil production operations were conducted in Colombia and in the United States of America. The cost of unevaluated properties not being amortized, to the extent there is such a cost, is assessed quarterly to determine whether the value has been impaired below the capitalized cost. The cost of any impaired property is transferred to the balance of oil and gas properties being depleted. The costs associated with unevaluated properties relate to projects which were undergoing exploration or development activities or in which we intend to commence such activities in the future. We will begin to amortize these costs when proved reserves are established or impairment is determined.

 

In accordance with SFAS No. 143, "Accounting for Asset Retirement Obligations," as codified by FASC ASC topic 410 (“ASC 410”), we report a liability for any legal retirement obligations on our oil and gas properties. The asset retirement obligations represent the estimated present value of the amounts expected to be incurred to plug, abandon, and remediate the producing properties at the end of their productive lives, in accordance with state laws, as well as the estimated costs associated with the reclamation of the property surrounding. The Company determines the asset retirement obligations by calculating the present value of estimated cash flows related to the liability. The asset retirement obligations are recorded as a liability at the estimated present value as of the asset's inception, with an offsetting increase to producing properties. Periodic accretion of the discount related to the estimated liability is recorded as an expense in the statement of operations.

 

The estimated liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells, and a risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligations. Revisions to the asset retirement obligations are recorded with an offsetting change to producing properties, resulting in prospective changes to depletion and depreciation expense and accretion of the discount. Because of the subjectivity of assumptions and the relatively long lives of most of the wells, the costs to ultimately retire the Company's wells may vary significantly from prior estimates.

 

 

Revenue Recognition

  

We recognize revenue upon transfer of ownership of the product to the customer which occurs when (i) the product is physically received by the customer, (ii) an invoice is generated which evidences an arrangement between the customer and us, (iii) a fixed sales price has been included in such invoice and (iv) collection from such customer is probable.

 

We recognize sales from one of our properties using the sales method. Under the sales method, the working interest owners recognize sales of oil and gas regardless of the amount produced for the period. The sales method assumes that any production sold by a working interest owner comes from that party’s share of the total reserves in place. Thus, whatever quantity is sold in any given period is the revenue for that party. No receivables, payables or unearned revenue are recorded unless a working interest owner’s aggregate sales from the property exceed its share of the total reserves in place. If such a situation arises, the parties would likely choose to cash balance or in some instances, the over delivered partner might choose to negotiate to buy out the under delivered party’s share. At September 30, 2011, we recognized sales of $1,262 and 13 barrels in excess of production. At December 31, 2010, we recognized sales of $108,918 and 1,344 barrels in excess of production. At September 30, 2011, the Company’s share of reserves exceeded 200,596 barrels.

 

Off-Balance Sheet Arrangements

  

Our Company has not entered into any transaction, agreement or other contractual arrangement with an entity unconsolidated with us under which we have

 

·

an obligation under a guarantee contract,

·

a retained or contingent interest in assets transferred to the unconsolidated entity or similar arrangement that serves as credit, liquidity or market risk support to such entity for such assets,

·

any obligation, including a contingent obligation, under a contract that would be accounted for as a derivative instrument, or

·

any obligation, including a contingent obligation, arising out of a variable interest in an unconsolidated entity that is held by us and material to us where such entity provides financing, liquidity, market risk or credit risk support to, or engages in leasing, hedging or research and development services with us.

·          

Item 3.

Quantitative and Qualitative Disclosures about Market Risk

 

Our company is a Smaller Reporting Company. A Smaller Reporting Company is not required to provide the disclosure information required by this item.

 

Item 4.

Controls and Procedures

 

The Company’s management, including the Company’s principal executive officer and principal financial officer, evaluated the effectiveness of the Company’s “disclosure controls and procedures,” as such term is defined in Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended, (the “Exchange Act”). Based upon their evaluation, the principal executive officer and principal financial offer concluded that, as of the end of the period covered by this report, the Company’s disclosure controls and procedures were not effective for the purpose of ensuring that the information required to be disclosed in the reports that the Company files or submits under the Exchange Act with the Securities and Exchange Commission (the “SEC”) (1) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (2) is accumulated and communicated to the Company’s management, including its principal executive and principal financial offers, as appropriate to allow timely decisions regarding required disclosure.

 

Management conducted an assessment of the effectiveness of the Company’s internal control over financial reporting as of September 30, 2011, utilizing a top-down, risk based approach described in SEC Release No. 34-55929 as suitable for smaller public companies.  Based on this assessment, management determined that the Company’s internal control over financial reporting as of September 30, 2011 is not effective. Based on this assessment, management has determined that, as of September 30, 2011, there were material weaknesses in our internal control over financial reporting. The material weaknesses identified during management's assessment was the lack of independent oversight by an audit committee of independent members of the Board of Directors. As defined by the Public Company Accounting Oversight Board Auditing Standard No. 5, a material weakness is a deficiency or a combination of deficiencies, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected. Given the difficulty of finding qualified individuals who are willing to serve as independent directors, there has been no change in the audit committee.

 

 

Our internal control over financial reporting includes policies and procedures that pertain to the maintenance of records that accurately and fairly reflect, in reasonable detail, transactions and dispositions of assets; and provide reasonable assurances that: (1) transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States; (2) receipts and expenditures are being made only in accordance with authorizations of management and the directors of the Company; and (3) unauthorized acquisitions, use, or disposition of the Company’s assets that could have a material affect on the Company’s financial statements are prevented or timely detected.

 

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparations and presentations. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

 

This quarterly report does not include an attestation report of the Company’s independent registered public accounting firm regarding internal control over financial reporting. As a Smaller Reporting Company, our Management’s report was not subject to attestation by the Company’s independent registered public accounting firm pursuant to rules of the Securities and Exchange Commission.

 

Except as indicated herein, there were no changes in the Company’s internal control over financial reporting during the three months ended September 30, 2011 that have materially affected, or are reasonable likely to materially affect, the Company’s internal control over financial reporting.

 

PART II – OTHER INFORMATION

 

Item 1.

Legal Proceedings

 

We are not a party to, or the subject of, any material pending legal proceedings other than ordinary, routine litigation incidental to our business.

 

Item 1A.

Risk Factors

 

Our company is a Smaller Reporting Company. A Smaller Reporting Company is not required to provide the risk factor disclosure required by this item.

 

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

 

(a)

None

(b)      

(b)

None

 

(c)

None

 

Item 3

Default upon Senior Securities

 

None

 

Item 4

Removed and Reserved

 

None

 

  

Item 5

Other Information

 

(a)

None

 

(b)

None

 

Item 6

Exhibits

 

See Exhibit Index attached hereto.

 

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 of the undersigned thereunto duly authorized.

 

	OSAGE EXPLORATION AND DEVELOPMENT, INC. (Registrant)
Date:  November 10, 2011	By:	/s/ Kim Bradford
		Kim Bradford
		President and Chief Executive Officer

 

Date:  November 10, 2011	By:	/s/ Kim Bradford
		Kim Bradford Principal Financial Officer

 

 

EXHIBIT INDEX

 

The following is a list of Exhibits required by Item 601 of Regulation S-K. Except for these exhibits indicated by an asterisk which are filed herewith, the remaining exhibits below are incorporated by reference to the exhibit previously filed by us as indicated.

 

Exhibit No.		Description
3.1		Articles of Incorporation of Osage Exploration and Development, Inc. (1)
3.2		Bylaws of Osage Exploration and Development, Inc. (2)
31.1 *		Certification pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, signed by Kim Bradford, President and Chief Executive Officer (Principal Executive Officer)
31.2 *		Certification pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, signed by Kim Bradford, Chief Financial Officer (Principal Financial Officer).
32.1 *		Certification pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, signed by Kim Bradford, President and Chief Executive Officer (Principal Executive Officer and Principal Financial Officer).

 

101.INS*		XBRL Instance Document
101.SCH*		XBRL Taxonomy Extension Schema
101.CAL*		XBRL Taxonomy Extension Calculation Linkbase
101.DEF*		XBRL Taxonomy Extension Definition Linkbase
101.LAB*		XBRL Taxonomy Extension Label Linkbase
101.PRE*		XBRL Taxonomy Presentation Linkbase

  

(1)

Incorporated herein by reference to Exhibit 3.1 to the Osage Exploration and Development, Inc. Form 10-SB Amendment No. 1 filed August 27, 2007

(2)		Incorporated herein by reference to Exhibit 3.2 to the Osage Exploration and Development, Inc. Form 10-SB Amendment No. 1 filed August 27, 2007
*		Filed herewith