UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

 

FORM 10-Q

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

For the quarterly period ended: June 30, 2011

or

/ / 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 registrant as specified in its charter)

_________________

Delaware	0-52718	26-0421736
(State or Other Jurisdiction	(Commission	(I.R.S. Employer
of Incorporation or Organization)	File Number)	Identification No.)

2445 5th Avenue

Suite 310

San Diego, CA 92101
(Address of Principal Executive Offices) (Zip Code)

(619) 677-3956
(Registrant’s telephone number, including area code)

N/A
(Former name or former address and former fiscal year, if changed since last report)

_________________

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 /X /            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 / 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 in Rule 12b-2 of the Exchange Act.

 

Large Accelerated Filer / /            Accelerated Filer / /

Non-Accelerated Filer / /            Smaller Reporting Company /x/

 

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

Yes / /            No/x /

The number of outstanding shares of the registrant's Common Stock, $0.0001 par value, as of August 12, 2011 was 47,299,775

i

PART I — FINANCIAL INFORMATION

Item 1.	Financial Statements
	Consolidated Balance Sheets; June 30, 2011 and December 31, 2010	1
	Consolidated Statements of Operations; Three and Six Months ended June 30, 2011 and 2010	2
	Consolidated Statements of Cash Flows; Three and Six Months ended June 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	11
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	19
Item 4.	Controls and Procedures	19

PART II — OTHER INFORMATION

Item 1.	Legal Proceedings	20
Item 1A.	Risk Factors	20
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	20
Item 3.	Defaults Upon Senior Securities	20
Item 4.	Submission of Matters to a Vote of Security Holders	20
Item 5.	Other Information	20
Item 6.	Exhibits	20
	Signatures	21

ii

PART I. FINANCIAL INFORMATION

 

Item 1. Financial Statements

 

OSAGE EXPLORATION AND DEVELOPMENT, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

June 30, 2011 and December 31, 2010

 

		2011				2010
ASSETS		(unaudited)
Current Assets:
Cash and equivalents		$	3,277,156			$	307,566
Accounts receivable, net of $0 allowance			292,262				74,678
Prepaid expenses			61,188				39,441
Total Current Assets			3,630,606				421,685
Property and Equipment, at cost:
Oil and gas properties and equipment			2,764,536				2,818,833
Capitalized asset retirement costs			46,146				46,146
Other property & equipment			56,823				54,861
			2,867,505				2,919,840
Less: accumulated depletion, depreciation and amortization			(1,225,252	)			(939,639	)
			1,642,253				1,980,201
Bank CD pledged for bond			30,000				30,000
Note receivable			11,000				—
Total Assets		$	5,313,859			$	2,431,886
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable		$	164,774			$	202,880
Accrued expenses			938,797				872,308
Total Current Liabilities			1,103,571				1,075,188
Liability for Asset Retirement Obligations			58,848				57,746
Total Liabilities			1,162,419				1,132,934
Commitments and Contingencies
Stockholders' Equity:
Common stock, $0.0001 par value, 190,000,000 shares authorized;
47,299,775 and 46,649,775 shares issued and outstanding			4,730				4,665
Additional-Paid-in-Capital			11,930,779				11,795,844
Stock Purchase Notes Receivable			(95,000	)			(95,000	)
Accumulated Deficit			(7,382,987	)			(10,093,679	)
Accumulated Other Comprehensive Loss - Currency Translation Loss			(306,082	)			(312,878	)
Total Stockholders' Equity			4,151,440				1,298,952
Total Liabilities and Stockholders' Equity		$	5,313,859			$	2,431,886

 

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

  

OSAGE EXPLORATION AND DEVELOPMENT, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF OPERATIONS
(unaudited)

		Three Months Ended June 30,								Six Months Ended June 30,
		2011				2010				2011				2010
Operating Revenues
Oil Revenues		$	639,622			$	374,348			$	1,013,133			$	691,818
Pipeline Revenues			322,828				—				591,061				107,293
Total Operating Revenues			962,450				374,348				1,604,194				799,111
Operating Costs and Expenses
Operating			228,822				153,877				419,176				289,013
General and Administrative			785,154				430,296				1,139,832				1,632,345
Depreciation, Depletion and Accretion			110,889				86,782				209,707				177,407
Stock Based Compensation			100,000				—				100,000				—
Total Operating Expenses			1,224,865				670,955				1,868,715				2,098,765
Operating Loss			(262,415	)			(296,607	)			(264,521	)			(1,299,654	)
Other Income (Expenses):
Interest Income			1,440				819				1,669				2,210
Interest Expense			(80,551	)			(525	)			(136,102	)			(1,061	)
Gain from Assignment of Leases			3,109,646				—				3,109,646				—
Income/ (Loss) before Income Taxes			2,768,120				(296,313	)			2,710,692				(1,298,505	)
Provision for Income Taxes			—				—				—				—
Net Income/ (Loss)			2,768,120				(296,313	)			2,710,692				(1,298,505	)
Other Comprehensive Income/ (Loss), net of tax:
Foreign Currency Translation Adjustment			32				(115,620	)			6,796				(130,964	)
Comprehensive Income/ (Loss)		$	2,768,152			$	(411,933	)		$	2,717,488			$	(1,429,469	)
Basic and Diluted Income/ (Loss) per Share		$	0.06			$	(0.01	)		$	0.06			$	(0.03	)
Weighted average number of common share
and common share equivalents used to
compute basic and diluted Loss per Share			47,015,160				45,841,094				46,833,477				46,016,129

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

OSAGE EXPLORATION AND DEVELOPMENT, INC. AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF CASH FLOWS

Six Months Ended June 30, 2011 and June 30, 2010
(unaudited)
			June 30, 2011				June 30, 2010
Cash flows from Operating Activities:
Net Income/ (Loss)		$	2,710,692			$	(1,298,505	)
Adjustments to reconcile net income/ (loss) to net cash
provided by operating activites:
Shares issued for services			100,000				—
Shares issued for interest			35,000				—
Gain on Assignment of Leases			(3,109,646	)			—
Accretion of Asset Retirement Obligation			1,102				1,002
Provision for depletion, depreciation
amortization and valuation allowance			209,707				177,407
Changes in operating assets and liabilities:
(Increase)/Decrease in accounts receivable			(244,458	)			64,976
(Increase) in other current assets			(33,718	)			—
Decrease in prepaid expenses			13,138				12,795
(Decrease)/ Increase in accounts payable and accrued expenses			(45,566	)			834,196
Net cash used by operating activities			(363,749	)			(208,129	)
Cash flows from Investing Activities:
Net Proceeds from Assignment of Leases			4,350,000				—
Investments in Oil & Gas Properties			(1,016,029	)			(59,177	)
Investment in Non Oil and Gas Assets			(1,962	)			—
Net cash provided/ (used) by investing activities			3,332,009				(59,177	)
Cash flows from Financing Activities:
Proceeds from Promissory Notes			700,000				—
Payments on Promissory Note			(700,000	)			(1,977	)
Net cash (used) by financing activities			—				(1,977	)
Effect of exchange rate on cash and equivalents			1,330				(11,686	)
Net increase/ (decrease) in cash and equivalents			2,969,590				(280,969	)
Cash and equivalents beginning of period			307,566				1,174,989
Cash and equivalents at end of period		$	3,277,156			$	894,020
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash Payment for Interest		$	100,000			$	24
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

June 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 (“USA”) 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 (“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 $7,382,987 at June 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 a profitable level of 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 accounting principles generally accepted in the United States 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 $2,396,522 at June 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. As of December 31, 2010, no allowance for doubtful accounts has been recorded.

 

Sales to one customer comprised approximately 65% and 62% of Osage’s total revenues for the three and six months ended June 30, 2011. 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 June 30, 2011, 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 six months ending June 30, 2011, we recognized sales of $62,564 and 617 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 June 30, 2011, the company’s share of reserves exceeded 109,743 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.

 

Subsequent Events

 

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

 

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.

 

Income Tax

 

The Company follows FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes,” as codified by FASB ASC topic 740 (“ASC 740”). 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 certain 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 statements of income.

 

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 June 30, 2011 and December 31, 2010:

 

 

 

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 located in Logan County, OK for gross consideration of $4,875,000. The Parties have a 60 day period from the signing of the Participation Agreement to conduct further due diligence and to confirm the acreage assigned. On June 16, 2011, we entered into the First Amendment to the Participation Agreement, increasing the due diligence period from 60 days to 105 days. 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. 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:

 

 

 

5. 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, has a loan fee and prepaid interest of 250,000 shares of common stock, $0.0001 par value, valued at $35,000, and is secured by an assignment of the Company’s future oil and gas leases in Logan County, OK. The Company was only permitted to use the proceeds from the Secured Promissory Note to acquire additional oil and gas leases. 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 agreed upon through an arms-length negotiations.

 

6. 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 that 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 June 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 June 30, 2011 under operating leases are as follows by year:

 

 

 

Rental expense totaled $13,163 and $13,700 for the three months ended June 30, 2011 and 2010, respectively. Rental expense charged to operations totaled $27,100 and $27,155 for the six months ended June 30, 2011 and 2010, respectively.

 

LEGAL PROCEEDINGS

 

The Company is not a party to any litigation that has arisen in the normal course of its business and that of its subsidiaries.

 

The Company recorded a charge in General and Administrative Expenses in the quarter ending March 31, 2010 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 General and Administrative Expenses 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.

 

 

7. MAJOR CUSTOMERS

 

During 2011 and 2010, the Company had three customers that accounted for all of its sales.

 

 

 

8. 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:

 

 

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, but not the pipeline, 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 royalty amount 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 2011, 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 1,000 feet in gross thickness and the targeted porosity zone is between 50 and 250 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 a 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, Oklahoma for gross consideration of $4,875,000. The Parties have a 60 day period from the signing of the Participation Agreement to conduct further due diligence and to confirm the acreage assigned. On June 16, 2011, we entered into the First Amendment to the Participation Agreement, increasing the due diligence period from 60 days to 105 days. 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. 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, which they may or may not acquire. We have yet to drill any wells and, therefore, have no basis to estimate whether such properties will produce oil and natural gas at all or in sufficient quantities so as to be profitable.

 

 

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 small 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 June 30, 2011 compared to Three Months ended June 30, 2010

 

 

Oil Sales

 

Oil Sales were $639,622, an increase of $265,274, or 70.9%, in 2011 compared to $374,348 in 2010. The increase is due primarily to an increase in oil prices and an increase in oil barrels (“BBLs”) sold in Colombia. In Colombia, we sold 6,000 BBLs at an average gross price of $104.80 per barrel in 2011 compared to 5,000 BBLs at an average gross price of $71.37 in 2010. In the United States, we sold 148 BBLs at an average gross price of $96.89 in 2011 compared to 323 BBLs at an average gross price of $69.45 in 2010.

 

Pipeline Sales

 

The Guaduas pipeline connects with the ODC pipeline (the “ODC Pipeline”) to transport oil to the port of Covenas in Colombia. In the quarter ending June 30 2010, we did not have any pipeline sales, as the ODC Pipeline was operating at full capacity and we were not able to transport oil over our pipeline. Pipeline sales began again in the third quarter of 2010. In 2011, the pipeline transported 1.99 million BBls (our share was approximately 187,000 BBLs).

 

Total revenues were $962,450, an increase of $588,102, or 157.1% in 2011 compared to $374,348 in 2010. Oil sales accounted for 66.5% and 100.0% of total revenues in 2011 and 2010, respectively.

 

 

Production

 

 

 

Production, net of royalties, was 4,956 BBLs, an increase of 45 BBLs, or 0.9% in 2011 compared to 4,911 BBLs in 2010. Colombian production increased by 220 BBLs, while production in the United States decreased by 175 BBls. Colombian production accounted for 97.0% and 93.4% of total production in 2011 and 2010, respectively.

 

Operating Costs and Expenses

 

 

Operating Expenses

 

Our operating expenses were $228,822 in 2011 compared to $153,877 in 2010, due primarily to an increase in operating costs in Colombia. Operating expenses as a percentage of total revenues decreased to 23.8% in 2011 from 41.1% in 2010 as the increase in revenues was much greater than the increase in operating expenses.

 

General and Administrative Expenses

 

General and administrative expenses were $785,154 in 2011, an increase of $354,858 or 82.5%, compared to $430,926 in 2010. Excluding the Colombian equity taxes of $310,297 as more fully described in footnote 6 above, 2011 general and administrative expenses were $474,857 in 2011, or $44,561 higher than 2010 expenses. As a percent of total revenues, general and administrative expenses, excluding the Colombian equity taxes recorded in 2011, decreased from 114.9% in 2010 to 49.3% in 2011 as the increase in revenues was greater than the increase in general and administrative expenses.

 

Depreciation, depletion and accretion

 

Depreciation, depletion and accretion were $110,889 in 2011 and $86,782 in 2010. The increase is primarily due to increased Colombian oil production.

 

Stock Based Compensation Expense

 

Stock based compensation expense was $100,000 in 2011 compared to zero in 2010. 2011 stock based compensation expense resulted from the issuance of 400,000 shares to two consultants. The shares were valued based upon the closing stock price at the date of issuance.

 

Loss from Operations

 

Loss from operations was $262,415 and $296,607 in 2011 and 2010, respectively. Loss from operations improved by $34,192 as revenues increased by $588,102 while operating expenses increased by $553,910.

 

 

Interest Expense

 

Interest expense was $80,551 in 2011 compared to $525 in 2010, an increase of $80,026. $80,000 of the increase is related to the interest on the Blackrock Promissory Note and the amortization of value of the shares issued as loan fee and prepaid interest on the Secured Promissory Note.

 

Other Income

 

Other income totaled $3,111,086 in 2011 compared to $819 in 2010. 2011 included a gain of $3,109,646 from assignment of leases in the Nemaha Ridge prospect in Oklahoma pursuant to the Participation Agreement as more fully described in footnote 2 above.

 

Provision for Income Taxes

 

Provision for income taxes was zero in 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 $2,768,120 in 2011 compared to a net loss of $296,313 in 2010. The $3,064,433 improvement is due primarily to the $3,109,646 gain from assignment of leases in 2011.

 

Foreign Currency Translation Gain/ (Loss)

 

Foreign currency translation gain was $32 in 2011 compared to a foreign currency translation loss of $115,620 in 2010. The Colombian Peso to Dollar Exchange Rate averaged 1,800 and 1,952 for the three months ended June 30, 2011 and 2010, respectively and was 1,777 and 1,928 at June 30, 2011 and June 30, 2010, respectively.

 

Comprehensive Income /(Loss)

 

Comprehensive income was $2,768,152 in 2011 compared to a comprehensive loss of $411,933 in 2010. The $3,180,085 improvement is due primarily to the $3,109,646 gain from assignment of leases and a $115,652 improvement in foreign currency translation.

 

Results of Operations

 

Six Months ended June 30, 2011 compared to Six Months ended June 30, 2010

 

 

 

Oil Sales

 

Oil Sales were $1,013,133, an increase of $321,315, or 46.4%, in 2011 compared to $691,818 in 2010. The increase is due primarily to an increase in oil prices and an increase in BBL sold in Colombia. In Colombia, we sold 10,000 BBLs in 2011 at an average gross price of $102.80 per barrel compared to 9,000 BBLs at an average gross price of $73.47 in 2010. In the United States, we sold 308 BBLs at an average gross price of $90.63 in 2011 compared to 976 BBLs at an average gross price of $72.24 in 2010.

 

Pipeline Sales

 

Pipeline sales were $591,061, an increase of $483,768, or 450.9%, in 2011 compared to $107,293. In 2010, we did not have any pipeline sales in the quarter ending June 30, 2010. In 2011, the pipeline transported 3.56 million BBls (our share was approximately 334,000 BBLs) compared to 0.67 million BBls (our share was approximately 63,000 BBLs) in 2010.

 

Total revenues were $1,604,194, an increase of $805,083, or 100.7% in 2011 compared to $799,111 in 2010. Oil sales accounted for 63.2% and 86.6% of total revenues in 2011 and 2010, respectively.

 

Production

 

 

 

Production, net of royalties, was 9,690 BBLs, a decrease of 814 BBLs, or 7.7% in 2011 compared to 10,504 BBLs in 2010. Production decreased in both Colombia and the United States. Colombian production accounted for 96.8% and 90.7% of total production in 2011 and 2010, respectively.

 

Operating Costs and Expenses

 

 

 

Operating Expenses

 

Our operating expenses were $419,176 in 2011 compared to $289,013 in 2010, due primarily to an increase in operating costs in Colombia. Operating expenses as a percentage of total revenues decreased to 26.1% in 2011 from 36.2% in 2010 as the increase in revenues was much greater than the increase in operating expenses.

 

General and Administrative Expenses

 

General and administrative expenses were $1,139,832 in 2011, a decrease of $492,513 or 30.2%, compared to $1,632,345. Excluding the Colombian equity taxes, as described in footnote 6 above, of $310,297 and $860,937, in 2011 and 2010, respectively, 2011 general and administrative expenses were $829,535 in 2011 compared to $771,408 in 2010. As a percent of total revenues, general and administrative expenses, excluding the Colombian equity taxes, decreased from 96.5% in 2010 to 51.7% in 2011 as the increase in revenues was greater than the increase in general and administrative expenses.

 

 

 

Depreciation, depletion and accretion

 

Depreciation, depletion and accretion were $209,707 in 2011 and $177,407 in 2010. The increase is primarily due to increased Colombian oil production.

 

Stock Based Compensation Expense

 

Stock based compensation expense was $100,000 in 2011 compared to zero in 2010. 2011 stock based compensation expense resulted from the issuance of 400,000 shares to two consultants. The shares were valued based upon the closing stock price at the date of issuance.

 

Loss from Operations

 

Loss from operations was $264,521 and $1,299,654 in 2011 and 2010, respectively. Loss from operations improved by $1,035,133 as revenues increased by $805,083 and operating expenses decreased by $230,050.

 

Interest Expense

 

Interest expense was $136,102 in 2011 compared to $1,061 in 2010, an increase of $135,041. $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 $3,111,315 in 2011 compared to $2,210 in 2010. 2011 included a gain of $3,109,646 from assignment of leases in the Nemaha Ridge prospect in Oklahoma pursuant to the Participation Agreement as more fully described in footnote 2.

 

Provision for Income Taxes

 

Provision for income taxes was zero in 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 $2,710,692 in 2011 compared to a net loss of $1,298,505 in 2010. The $4,009,197 improvement is due primarily to the $3,109,646 gain from assignment of leases in 2011, the $674,920 improvement in revenues less operating expenses and the $550,640 decrease in the amount of Colombian equity taxes recognized in 2011 compared to 2010.

 

Foreign Currency Translation Gain/ (Loss)

 

Foreign currency translation gain was $6,796 in 2011 compared to a foreign currency translation loss of $130,964 in 2010. The Colombian Peso to Dollar Exchange Rate averaged 1,839 and 1,950 for the six months ended June 30, 2011 and 2010, respectively and was 1,777 and 1,928 at June 30, 2011 and June 30, 2010, respectively.

 

Comprehensive Income /(Loss)

 

Comprehensive income was $2,717,488 in 2011 compared to a comprehensive loss of $1,429,469 in 2010. The $4,146,957 improvement is due primarily to the $4,009,197 improvement in net income as well as the $137,760 improvement in foreign currency translation.

 

 

Liquidity and Capital Resources

 

We had working capital of $2,527,035 at June 30, 2011 compared to a working capital deficit of $653,503 at December 31, 2010. Working capital at June 30, 2011 consisted primarily of $3,277,156 of cash and equivalents and $292,262 of accounts receivable, offset by $938,797 of accrued expenses. 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 $363,749 in 2011 compared to net cash used by operating activities of $208,129 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 $244,458 increase in accounts receivable, offset by the $2,710,692 net income and $209,707 provision for depreciation and depletion. The major components of the net cash used by operating activities in 2010 were the $1,298,505 net loss, offset by the $834,196 increase in accounts payable and accrued expenses and the $177,407 provision for depreciation and depletion.

 

Net cash provided by investing activities in 2011 totaled $3,332,009 and consisted primarily of $4,350,000 net proceeds from assignment of leases, offset by $1,016,029 investments in oil and gas properties. Net cash used by investing activities in 2010 of $59,177 consisted entirely of investments 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 $1,977 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. Pacific Rubiales, owns 90.6% of the Guaduas field and is the operator.

 

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 approximately 1,838 and 1,950 in 2011 and 2010, respectively. The Colombian Peso to Dollar Exchange Rate was approximately 1,777 and 1,928 at June 30, 2011 and June 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 June 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 June 30, 2011, we recognized sales of $62,564 and 617 barrels in excess of production. At December 31, 2010, we recognized sales of $108,918 and 1,344 barrels in excess of production. At June 30, 2011, the company’s share of reserves exceeded 204,123 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 June 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 June 30, 2011 is not effective. Based on this assessment, management has determined that, as of June 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. Management’s report was not subject to attestation by the Company’s independent registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this quarterly report.

 

Except as indicated herein, there were no changes in the Company’s internal control over financial reporting during the three months ended June 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)

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:   August 12, 2011	By:	/s/  Kim Bradford
		Kim Bradford
		President and Chief Executive Officer

 

Date:  August 12, 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).

 

(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