Osage Exploration & Development (OSGE) 10-Q 2010 Q3 Quarterly report

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, 2010

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

For the transition period from _____ to _____

OSAGE EXPLORTION 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	(619) 677-3956
(Address of principal executive offices)	(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   x                             No o

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   o                             No o

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  o     Accelerated Filer   o

Non-Accelerated Filer  o     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  o                             No x

The number of outstanding shares of the registrant’s Common Stock, $0.0001 par value, as of August 6, 2010 was 45,149,775.

OSAGE EXPLORATION AND DEVELOPMENT, INC. AND SUBSIDIARY

TABLE OF CONTENTS

		Page
	PART I – FINANCIAL INFORMATION
Item 1.	Financial Statements (unaudited)
	Consolidated Balance Sheets: As of June 30, 2010 and December 31, 2009	1
	Consolidated Statement of Operations: Three and Six Months ended June 30, 2010 and 2009	2
	Consolidated Statement of Cash Flows: Six Months ended June 30, 2010 and 2009	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	19
Item 4.	Controls and Procedures	19
	PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	20
Item 1.A.	Risk Factors	20
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	20
Item 3	Default 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

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PART I. FINANCIAL INFORMATION

Item 1.              Financial Statements (Unaudited)

OSAGE EXPLORATION AND DEVELOMENT, INC.

CONSOLIDATED BALANCE SHEETS

As of June 30, 2010 and December 31, 2009

	June 30, 2010			December 31, 2009
ASSETS	(unaudited)
Current assets:
Cash and cash equivalents	$	894,020		$	1,174,989
Accounts receivable		91,797			156,211
Prepaid expenses		24,022			37,380
Total current assets		1,009,839			1,368,580
Property and equipment, at cost:
Oil and gas properties and equipment		2,353,601			2,174,793
Capitalized asset retirement costs		46,146			46,146
Other property & equipment		48,205			48,205
		2,447,952			2,269,144
Less: accumulated depletion, depreciation
and amortization		(734,694	)		(557,287	)
Property and equipment, net		1,713,258			1,711,857
Bank CD pledged for bond		30,000			30,000
Total assets	$	2,753,097		$	3,110,437
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	185,939		$	221,398
Accrued expenses		917,602			47,948
Promissory note		1,558			3,535
Total current liabilities		1,105,099			272,881
Asset retirement obligations		56,744			55,742
Total liabilities		1,161,843			328,623
Commitments and contingencies
Stockholders' equity:
Common stock, $0.0001 par value, 190,000,000 shares authorized;		4,506			4,696
45,059,775 and 46,959,775 shares issued and outstanding
as of June 30, 2010 and December 31, 2009, respectively.
Additional paid-in capital		11,756,703			11,804,013
Stock purchase notes receivable		(95,000	)		(142,500	)
Accumulated deficit		(9,770,714	)		(8,472,209	)
Accumulated other comprehensive loss -
currency translation loss		(304,241	)		(412,186	)
Total stockholders' equity		1,591,254			2,781,814
Total liabilities and stockholders' equity	$	2,753,097		$	3,110,437

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

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OSAGE EXPLORATION AND DEVELOPMENT, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

Three and Six Months ended June 30, 2010 and 2009

(unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
Operating revenues:
Oil revenues	$	374,348		$	210,942		$	691,818		$	463,486
Pipeline revenues		—			420,983			107,293			912,510
Total operating revenues		374,348			631,925			799,111			1,375,996
Operating costs and expenses:
Operating expenses		153,877			227,600			289,013			431,109
General and administrative expenses		430,296			529,047			1,632,345			1,075,111
Asset impairment		—			111,579			—			1,724,473
Depreciation and depletion		86,782			92,236			177,407			178,870
Stock based compensation expense		—			18,000			—			55,493
Total operating costs and expenses		670,955			978,462			2,098,765			3,465,056
Loss from operations		(296,607	)		(346,537	)		(1,299,654	)		(2,089,060	)
Other income/(expenses):
Interest income		819			7,916			2,210			24,442
Interest expense		(525	)		(1,342	)		(1,061	)		(2,676	)
Loss before income taxes		(296,313	)		(339,963	)		(1,298,505	)		(2,067,294	)
Provision for income taxes		—			—			—			—
Net Loss		(296,313	)		(339,963	)		(1,298,505	)		(2,067,294	)
Other comprehensive (loss)/income, net of  tax:
Foreign currency translation adjustment		(115,620	)		360,231			(130,964	)		53,300
Comprehensive (loss)/income	$	(411,933	)	$	20,268		$	(1,429,469	)	$	(2,013,994	)
Basic and diluted loss per share	$	(0.01	)	$	(0.01	)	$	(0.03	)	$	(0.04	)
Weighted average number of common share
and common share equivalents used to
compute basic and dilluted loss per share		45,841,094			46,504,830			46,016,129			46,359,775

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

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OSAGE EXPLORATION AND DEVELOPMENT, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

Six Months ended June 30, 2010 and 2009

(unaudited)

	Six Months Ended June 30,
	2010			2009
Cash flows from operating activities:
Net loss	$	(1,298,505	)	$	(2,067,294	)
Adjustments to reconcile net loss to net cash
provided by (used in) operating activites:
Asset impairment		—			1,724,473
Stock based compensation		—			7,493
Shares issued for services		—			48,000
Accretion of asset retirment obligations		1,002			35,005
Provision for depletion, depreciation and amortization		177,407			178,870
Changes in operating assets and liabilities:
Decrease/(increase) in accounts receivable		64,976			92,915
Decrease in prepaid expenses		12,795			30,859
Increase in accounts payable and accrued expenses		834,196			93,034
Net cash (used in)/provided by operating activities		(208,129	)		143,355
Cash flows from investing activities:
Increase in asset retirement obligations		—			(32,471	)
Pipeline reimbrusement by operator		—			797,483
Investment in bank CD pledged for letter of credit		—			(46,868	)
Maturity of bank CD pledged for letter of credit		—			145,632
Proceeds from assignemnt of 50% of Rosablanca		—			881,523
Investments in oil & gas properties		(59,177	)		(1,634,724	)
Interest earned on Bank CD pledged for letter of credit		—			(1,535	)
Payments from Colombian trust account		—			(379,480	)
Net cash used in investing activities		(59,177	)		(270,440	)
Cash flows from financing activities:
Payments on promissory note		(1,977	)		(1,396	)
Net cash used in financing activities		(1,977	)		(1,396	)
Effect of exchange rate on cash and cash equivalents		(11,686	)		76,735
Net decrease in cash and cash equivalents		(280,969	)		(51,746	)
Cash and Cash equivalents, beginning of period		1,174,989			988,508
Cash and Cash equivalents, end of period	$	894,020		$	936,762
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash payments for interest	$	24		$	142
Cash payments for income taxes	$	—		$	—
Non-cash transactions:
Forgiveness of accounts payable by LEC	$	—		$	1,985,043
Forgiveness of joint operating account by Pacific	$	—		$	799,007
Issuance of shares to LEC in conjunction with the LEC Agreement	$	—		$	420,000
Cancellation of shares for notes receivable	$	47,500		$	—

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

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OSAGE EXPLORATION AND DEVELOPMENT, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2010 (unaudited)

1. BASIS OF PRESENTATION

Osage Exploration and Development, Inc. (“Osage”, “We”, “Our” 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 2009 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 consolidated financial statements reflect all adjustments and disclosures, which, in the Company’s opinion, are necessary for fair presentation of the financial position, results of operations and changes in cash flow. 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.

Liquidity and Going Concern

The Company incurred significant losses since its inception and has an accumulated deficit of $9,770,714 at June 30, 2010 and $8,472,209 at December 31, 2009.  Substantial portions of the losses are attributable to asset impairment charges, stock based compensation, professional fees, Colombian equity tax associated with our Cimarrona property 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) attempting to increase our current production, (b) controlling overhead and expenses and (c) 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.

IMPACT OF RECENT ACCOUNTING PRONOUNCEMENTS

Recent Pronouncements

In June 2009, the FASB issued Financial Accounting Standard No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles – a replacement of FASB Statement No. 162” (“SFAS 168”).  In addition, in September 2009, the FASB issued Accounting Standards Update No. 2009-01, “Topic 205 – Generally Accepted Accounting Principles - amendments based on Statement of Financial Accounting Standards No. 168 – The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles” (“ASU 2009-1”). Both SFAS 168 and ASU 2009-1 recognize the FASB Accounting Standards Codification as the source of authoritative U.S. GAAP to be utilized by nongovernmental entities. SFAS 168 and ASU 2009-1 are effective for interim and annual periods ending after September 15, 2009. The adoption of this pronouncement did not have a material impact on the Company’s financial statements.

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On February 25, 2010, the FASB issued ASU No. 2010-09 Subsequent Events Topic 855 “Amendments to Certain Recognition and Disclosure Requirements,” effective immediately. The amendments in the ASU remove the requirement for an SEC filer to disclose a date through which subsequent events have been evaluated in both issued and revised financial statements. Revised financial statements include financial statements revised as a result of either correction of an error or retrospective application of US GAAP. The FASB believes these amendments remove potential conflicts with the SEC’s literature. The adoption of this ASU did not have a material impact on the Company’s consolidated financial statements.

On March 5, 2010, the FASB issued ASU No. 2010-11 Derivatives and Hedging Topic 815 “Scope Exception Related to Embedded Credit Derivatives.” This ASU clarifies the guidance within the derivative literature that exempts certain credit related features from analysis as potential embedded derivatives requiring separate accounting. The ASU specifies that an embedded credit derivative feature related to the transfer of credit risk that is only in the form of subordination of one financial instrument to another is not subject to bifurcation from a host contract under ASC 815-15-25, Derivatives and Hedging — Embedded Derivatives — Recognition. All other embedded credit derivative features should be analyzed to determine whether their economic characteristics and risks are “clearly and closely related” to the economic characteristics and risks of the host contract and whether bifurcation is required. The ASU is effective for the Company on July 1, 2010. Early adoption is permitted. The adoption of this ASU will not have a material impact on the Company’s consolidated financial statements.

In April 2010, the FASB codified the consensus reached in Emerging Issues Task Force Issue No. 08-09, “Milestone Method of Revenue Recognition.” FASB ASU No. 2010-17 provides guidance on defining a milestone and determining when it may be appropriate to apply the milestone method of revenue recognition for research and development transactions. FASB ASU No. 2010 – 17 is effective for fiscal years beginning on or after June 15, 2010, and is effective on a prospective basis for milestones achieved after the adoption date. The Company does not expect this ASU will have a material impact on its financial position or results of operations when it adopts this update on January 1, 2011.

In March 2008, the FASB issued SFAS No. 161, "Disclosures about Derivative Instruments and Hedging Activities,” as codified by FASB ASC topic 815 “Derivatives and Hedging” (“ASC 815”).  ASC 815 requires enhanced disclosures about an entity’s derivative and hedging activities.  The adoption of ASC 815 did not have a material impact on the Company’s financial statements.

In May 2008, the FASB issued SFAS No. 163, "Accounting for Financial Guarantee Insurance Contracts, an interpretation of FASB Statement No. 60," as codified by FASB ASC topic 944 “Financial Services – Insurance” (“ASC 944”).  The scope of ASC 944 is limited to financial guarantee insurance (and reinsurance) contracts, as described in this Statement, issued by enterprises included within the scope of Statement 60. Accordingly, ASC 944 does not apply to financial guarantee contracts issued by enterprises excluded from the scope of Statement 60 or to some insurance contracts that seem similar to financial guarantee insurance contracts issued by insurance enterprises (such as mortgage guaranty insurance or credit insurance on trade receivables), ASC 944 also does not apply to financial guarantee insurance contracts that are derivative instruments included within the scope of FASB Statement No. 133, "Accounting for Derivative Instruments and Hedging Activities," as codified by FASB ASC topic 815.  The adoption of ASC 944 did not have a material impact on the Company's financial statements.

In June 2009, the FASB issued FASB No. 166, “Accounting for Transfers of Financial Assets - an amendment of FASB Statement No. 140” (“SFAS 166”), as codified by FASB ASC topic 860 “Transfers and Servicing” (“ASC 860”).  ASC 860 requires additional disclosures about the transfer and derecognition of financial assets and eliminates the concept of qualifying special-purpose entities under SFAS 140.  ASC 860 is effective for fiscal years beginning after November 15, 2009. The adoption of ASC 860 did not have a material impact on the Company.

In June 2009, the FASB issued SFAS No. 167, “Amendments to FASB Interpretation No. 46(R)” (“SFAS 167”). SFAS 167 amends certain requirements of FASB Interpretation No. 46 (revised December 2003), “Consolidation of Variable Interest Entities”, as codified by FASC ASC topic 810 (“ASC 810”) to improve financial reporting by enterprises involved with variable interest entities and to provide more relevant and reliable information to users of financial statements. This Statement is effective as of the beginning of each reporting entity’s first annual reporting period that begins after November 15, 2009, for interim periods within that first annual reporting period, and for interim and annual reporting periods thereafter. The adoption of ASC 810 did not have a material impact on its results of operations or financial position.

5

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.

Significant Accounting Policies

Income Tax

On January 1, 2008, the Company adopted the provisions of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes,” as codified by FASB ASC topic 740 “Income Taxes” (“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 highly 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 2010 or 2009.  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 US operations for the current period.

2 .. OIL AND GAS PROPERTIES AND CAPITALIZED ASSET RETIREMENT COSTS

Oil and gas properties consisted of the following:

	June 30, 2010			December 31, 2009
Oil and gas properties and equipment	$	2,353,601		$	2,174,793
Capitalized asset retirement costs		46,146			46,146
Accumulated depreciation and depletion		(697,520	)		(490,918	)
Oil & Gas Properties, Net	$	1,702,227	��	$	1,730,021

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3. GEOGRAPHICAL INFORMATION

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

	Revenues for the			Revenues for the
	Three Months ended June 30, 2010			Three Months ended June 30, 2009
		Amount	% of Total		Amount	% of Total
Colombia	$	356,839	95.3%	$	606,800	96.0	%
United States		17,509	4.7%		25,125	4.0	%
Total	$	374,348	100.0%	$	631,925	100.0	%

	Revenues for the				Revenues for the
	Six Months ended June 30, 2010				Six Months ended June 30, 2009
	Amount		% of Total		Amount		% of Total
Colombia	$	745,367		93.3%	$	1,333,056		96.9	%
United States		53,744		6.7%		42,940		3.1	%
Total	$	799,111		100.0%	$	1,375,996		100.0	%

	Long Lived Assets at June 30, 2010			Long Lived Assets at December 31, 2009
Colombia	$	1,564,150	91.3%	$	1,555,604	90.9	%
United States		149,108	8.7%		156,253	9.1	%
Total	$	1,713,258	100.0%	$	1,711,857	100.0	%

4. COLOMBIAN TRUST ACCOUNTS

In September 2007, we entered into an agreement (the “Agreement”) with Gold Oil, Plc (“Gold”) and Empesa Petrolera de Servicios y Asesorias, S.A. (“EMPESA), whereby we farmed-in to the approximately 165 square miles Rosablanca concession in Colombia awarded by the Agencia Nacional de Hidrocarburos (“ANH”) to Gold in September 2007.  In 2007, we (i) paid $1,200,000 to Gold representing funds that Gold had previously issued to a trust established by the ANH to use for drilling the first well in the Rosablanaca concession and (ii) issued a letter of credit of $144,000 for the benefit of Gold’s bank in Colombia representing the guarantee required by the ANH.  We were obligated to commence drilling on the first well by December 26, 2008, which we have done.  Under the terms of the concession agreement with the ANH, we were required to perform six phases, with each phase lasting 12 months.  We performed the first phase, which was to drill the first well.  Each phase required us to fund a new trust account and issue a letter of credit as well as perform certain tasks.  Phase 2 required an establishment of a trust account for $790,000, of which our share was $197,500, and an issuance of a letter of credit in the amount of $110,000, of which our share was $25,000 and obligated us to perform certain seismic work.  In the first quarter of 2009, we funded both the trust account and the letter of credit.  We withdrew from the concession in 2009 and therefore wrote off all of the remaining balance in the trust account in 2009.  Accordingly, the balance of the Colombian trust accounts was zero at June 30, 2010 and December 31, 2009.

5. BANK CD PLEDGED FOR BOND

We maintain three certificates of deposits (“CD”), each for $10,000, with a bank in Oklahoma, which comprise the escrow arrangement with the Osage Indian Agency for our Osage, Oklahoma property.  The balance in the CDs was $30,000 at June 30, 2010 and December 31, 2009

BANK CD PLEDGED FOR LETTER OF CREDIT.

In August 2007, we placed $144,000 in a CD with a bank as collateral for the $144,000 letter of credit required by the ANH as more fully described in footnote 4 above.  In September 2008, we received an extension from ANH until December 26, 2008 to drill our first well and the CD was extended until March 25, 2009.  The letter of credit expired on March 25, 2009 and we redeemed the CD at that time.  Accordingly, the balance of this CD was zero at June 30, 2010 and December 31, 2009.

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6. PROMISSORY NOTE

On April 27, 2007, we purchased a truck to be used by our pumper in our Oklahoma property by issuing a promissory note (the “Promissory Note”) to a bank secured by the truck.  The Promissory Note matures October 27, 2010, has a variable interest rate of Prime plus 1.0% (4.25% as of June 30, 2010) and monthly principal and interest payments totaling $366.   The Promissory Note had a balance of $1,558 and $3,535 at June 30, 2010 and December 31, 2009, respectively.

7. COMMITMENTS AND CONTINGENCIES

ENVIRONMENT

Osage, as an 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 Company 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, 2010 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 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 is guaranteed by Mr. Kim Bradford, our President and Chief Executive Officer.  No compensation was given to Mr. Bradford for his guarantee. In addition, the Company is responsible for all operating expenses and utilities.  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 through June 30, 2011 under operating leases are $31,382.

Rental expense charged to operations totaled $13,700 and $27,155 for the three and six months ended June 30, 2010, respectively, and $13,332 and $26,428 for the three and six months ended June 30, 2009, respectively.

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.

The Company recorded an $860,937 charge in general and administrative expenses in 2010, in the first quarter of 2010, as we were notified by Division de Impuestos y Actuanas Nacionales (“DIAN”), the Colombian tax authorities, that Cimarrona owes $860,937 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 that the taxes were assessed upon, Cimarrona subtracted the cost of its non-producing wells in 2001 and 2003 from its taxable income during those years.  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.  The Company is appealing DIAN’s decision but has recorded this liability in accrued expenses at June 30, 2010.  In the event the Company loses its appeal, it believes it may need to begin paying the 2001 taxes by the end of 2010 and the 2003 taxes by the end of 2011.  The Company believes that, in the event it loses its appeal, it may be able to make these tax payments over a three to five year period.

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8. EQUITY TRANSACTIONS

Lewis Energy Colombia, Inc.

In March 2009, we entered into an agreement with LEC (the “LEC Agreement”), whereby LEC agreed to provide $3,500,000, to drill the first well and become operator of Rosablanca in return for a 50% assignment of our 50% operating interest in Rosablanca.  In addition, LEC was entitled to recoup two times its investment in the first well before Osage receives any cash flow from the first well.  The transaction was recorded in accordance with paragraph 47(c) SFAS 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies,” as codified in FASB ASC section 932-360-55.  Furthermore, as part of the LEC Agreement, we issued 5,250,000 shares of our Common Stock to an affiliate of LEC.  As a result of the LEC transaction, revenues and investments on all future wells in Rosablanca were to be allocated 40% to Gold, 25% to LEC, 25% to us and 10% to EMPESA.    We recognized no gain or loss on the assignment of our interest.  In March 2009, we announced that we completed testing on the first well without finding producible hydrocarbons in any of the zones evaluated.  In September 2009, we entered into a termination agreement (the “Termination Agreement”) with Gold, EMPESA and LEC, whereby we and LEC agreed to withdraw from the Rosablanca concession.

Notes Receivable

A note receivable with a face amount of $47,500, initially issued in 2006 and collateralized by 1,900,000 shares was cancelled during the first half of 2010 as the investor returned to the Company and the Company cancelled, 1,000,000 and 900,000 shares in the first quarter of 2010 and second quarter of 2010, respectively.

9. MAJOR CUSTOMERS

The following table sets forth revenues by customer for the periods reported:

	Three Months ended June 30, 2010				Three Months ended June 30, 2009
	Amount		% of Total		Amount		% of Total
HOCOL	$	356,839		95.3%	$	185,817		29.4%
Sunoco		17,509		4.7%		25,125		4.0%
Pacific		—		—		420,983		66.6%
Total	$	374,348		100.0%	$	631,925		100.00%

	Six Months ended June 30, 2010				Six Months ended June 30, 2009
	Amount		% of Total		Amount		% of Total
HOCOL	$	638,074		79.8%	$	420,746		30.6%
Pacific		107,293		13.4%		912,350		66.3%
Sunoco		53,744		6.7%		42,900		3.1%
Total	$	799,111		100.0%	$	1,375,996		100.0%

9

10. 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:

	June 30, 2010						December 31, 2009
	Colombia		United States		Combined		Colombia		United States		Combined
Beginning Balance	$	35,719	$	20,023	$	55,742	$	—	$	18,203	$	18,203
Additions for new wells		—		—		—		32,471		—		32,471
Accretion expense		—		1,002		1,002		3,248		1,820		5,068
Ending Balance	$	35,719	$	21,025	$	56,744	$	35,719	$	20,023	$	55,742

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 statements to reflect events or circumstances after the date hereof or to reflect the occurrence of unanticipated events.

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In September 2007, we entered into an agreement (the “Agreement”) with Gold Oil, PLC (“Gold”)and Empesa Petrolera de Servicios y Asesorias, S.A. (“EMPESA), whereby we farmed-in to the approximately 165 square miles Rosablanca concession in Colombia awarded by the Agencia Nacional de Hidrocaburos (“ANH”) to Gold in June, 2007.  Under the Agreement, we were considered the operator of the concession and, therefore, required to pay all costs associated with drilling and testing of the first well on the Rosablanca project.  Revenues generated from the first well were initially to be allocated 50% to us, 40% to Gold and 10% to Empesa.  In March 2009, we entered into the LEC Agreement with LEC whereby LEC shall provide all of the capital required to drill the first well, up to a maximum of $3,500,000.  As part of the $3,500,000 maximum investment amount by LEC, LEC also agreed to reimburse us for certain amounts we have already spent on the first well.  Under the LEC Agreement, we assigned Lewis 50% of our 50% interest in the Rosablanca concession and have made LEC the operator.  In addition, LEC was entitled to recoup two times its investment in the first well before we receive any cash flow derived from the first well.  Furthermore, as part of the LEC Agreement, we issued 5,250,000 shares of our common stock to an affiliate of LEC.  As a result of the LEC transaction, revenues and investments on all future wells in Rosablanca will be allocated 40% to Gold, 25% to LEC, 25% to us and 10% to Empesa.    If any party doesn’t contribute its share of the costs, its revenue interest will automatically be transferred to the party that provides the capital.  On March 23, 2009, we announced that we completed testing on the first well without finding producible hydrocarbons in any of the zones evaluated.  In September 2009, we entered into the Termination Agreement with Gold, EMPESA and Lewis, whereby we and Lewis withdrew from the Rosablanca concession.  Therefore, we wrote off our entire investment in the Rosablanca concession as of December 31, 2009.

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 2010 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.

Going Concern

We anticipate we will need to raise at least $1,000,000 to provide for requirements for the next twelve months.  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) raising additional capital and/or obtaining financing; (b) increasing our current production and (c) controlling overhead and expenses.

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.

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Results of operations

Three months ended June 30, 2010 compared to three months ended June 30, 2009

	2010				2009				Change
	Amount		Percentage		Amount		Percentage		Amount			Percentage
Oil sales	$	374,348		100.0%	$	210,942		33.4%	$	163,406			77.5%
Pipeline Sales		—		0.0%		420,983		66.6%		(420,983	)		-100.0%
Total revenues	$	374,348		100.0%	$	631,925		100.0%	$	(257,577	)		-40.8%

Oil sales

Oil sales were $374,348, an increase of $163,406, or 77.5%, in 2010 compared to $210,942 in 2009.   The increase is primarily due to an increase in oil prices and increases in unit sales in Colombia.  In Colombia, we sold 5,000 barrels (“BBLs”) at an average gross price of $73.96 in 2010, compared to 4,000 BBLs at an average gross price of $48.90 in 2009.  In the United States, we sold 323 BBLs at an average gross price of $72.24 in 2010 compared to 635 BBLs at an average gross price of $52.44 in 2009.

Pipeline sales

Pipeline sales were $0 in 2010 compared to $420,983 in 2009.   The Guaduas pipeline connects with the ODC pipeline (the “ODC Pipeline”) to transport oil to the port of Covenas in Colombia.  Beginning in early 2010, the ODC Pipeline has been operating close to full capacity, and during the second quarter of 2010, the pipeline operated at full capacity.  This has severely restricted our ability to transport oil over our pipeline.  Unless conditions improve with the ODC Pipeline, or additional pipeline are built, we anticipate that pipeline sales will either remain at zero or at least be significantly below the 2009 levels.   In 2010, the pipeline did not transport any oil, while in 2009, the pipeline transported approximately 2.6 million BBLs (our share was approximately 244,000 BBLs).

Total revenues

Total revenues were $374,348, a decrease of $257,577, or 40.8% in 2010 compared to $631,925 in 2009.  Oil sales accounted for 100.0% and 33.4% of total revenues in 2010 and 2009, respectively.

Production

	2010				2009				Increase/(Decrease)
	Net Barrels		% of Total		Net Barrels		% of Total		Barrels			%
Colombia		4,588		93.4%		5,853		90.2%		(1,265	)		-21.6%
United States		323		6.6%		635		9.8%		(312	)		-49.1%
Total		4,911		100.0%		6,488		100.0%		(1,577	)		-24.3%

Production, net of royalties, was 4,911 BBLs, a decrease of 1,577 BBLs, or 24.3% in 2010 compared to 6,488 BBLs in 2009 primarily due to production decreases in Colombia.  Colombia production accounted for 93.4% and 90.2% of total production in 2010 and 2009, respectively.

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Operating costs and expenses

	2010				2009				Change
	Amount		Percentage		Amount		Percentage		Amount			Percentage
Operating expenses
Operating expenses	$	153,877		41.1%	$	227,600		36.0%	$	(73,723	)		-32.4%
General & administrative expenses		430,296		114.9%		529,047		83.7%		(98,751	)		-18.7%
Asset impairment		—		0.0%		111,579		17.7%		(111,579	)		N/A
Depreciation and depletion		86,782		23.2%		92,236		14.6%		(5,454	)		-5.9%
Stock based compensation expense		—		0.0%		18,000		2.8%		(18,000	)		-100.0%
Total operating costs and expenses	$	670,955		179.2%	$	978,462		154.8%	$	(307,507	)		-31.4%

Operating expenses

Operating expenses were $153,877 in 2010, a $73,723 decrease or 32.4%, compared to $227,600 in 2009.  The decrease is due primarily to a decrease in operating costs in Colombia, consistent with production decreases.  Operating expenses as a percentage of total revenues increased to 41.1% in 2010 from 36.0% in 2009 as the decrease in revenues exceeded the decrease in operating expenses.

General and administrative expenses

General and administrative expenses were $430,296 in 2010, a $98,751 decrease or 18.7%, compared to $529,047 in 2009.  The decrease is primarily due to lower general and administrative expenses in Colombia.  General and administrative expenses as a percentage of total revenues increased to 114.9% in 2010 from 83.7% in 2009 as the decrease in revenues exceeded the decrease in general and administrative expenses.

Asset impairment

No asset impairment charge was recorded in 2010.  We recorded an asset impairment charge of $111,579 in 2009 relating to our first well at Rosablanca as we found no producible hydrocarbons.

Depreciation and  depletion

Depreciation and depletion were $86,782 in 2010 and $92,236 in 2009.  The decrease in 2010 is due primarily to decreased depletion expense resulting from lower production.

Stock based compensation expense

No stock based compensation expense was recorded in 2010.  Stock based compensation in 2009 of $18,000 comprised of the value of shares issued to two consultants.  The shares were valued based on the stock price at the date of issuance.

Loss from operations

Loss from operations was $296,609 and $346,537 in 2010 and 2009, respectively.   Loss from operations improved by $49,930 due primarily to the $111,759 decrease in asset impairment charge in 2010 compared to 2009, the $98,751decrease in general and administrative expenses in 2010 compared to 2009, the $73,723 decrease in operating expenses in 2010 compared to 2009, offset by the $257,577 decrease in revenues in 2010 compared to 2009.

Interest income, net

Net interest income was $294 in 2010 compared to net interest income of $6,574 in 2009.  The decrease is primarily due to lower cash balances in 2010.

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Provision for income taxes

Provision for income taxes was zero in 2010 and 2009, due to losses incurred since inception.

Net loss

Net loss was $296,313 and $339,963 in 2010 and 2009, respectively.   The $43,650 improvement in net loss is due primarily to the improvement in loss from operations in 2010 compared to 2009.

Foreign currency translation loss

Foreign currency translation loss was $115,620 in 2010 compared to a foreign currency translation gain of $360,231 in 2009.  The Colombian Peso to Dollar Exchange Rate averaged 1,952 and 2,224 in 2010 and 2009, respectively and was 1,928 and 2,145 at June 30, 2010 and June 30, 2009, respectively.

Comprehensive loss

Comprehensive loss was $411,933 in 2010 compared to a comprehensive income of $20,268 in 2009.  Comprehensive loss decreased by $432,201 due primarily to the foreign currency translation loss in 2010 compared to a foreign currency translation gain in 2009.

Six months ended June 30, 2010 compared to six months ended June 30, 2009

	2010				2009				Change
	Amount		Percentage		Amount		Percentage		Amount			Percentage
Oil sales	$	691,818		86.6%	$	463,486		33.7%	$	228,332			49.3%
Pipeline sales		107,293		13.4%		912,510		66.3%		(805,217	)		-88.2%
Total revenues	$	799,111		100.0%		1,375,996		100.0%	$	(576,885	)		-41.9%

 

Oil sales

Oil sales were $691,818, an increase of $228,332, or 49.3%, in 2010 compared to $463,486 in 2009.   The increase is primarily due to an increase in oil prices, offset by a decrease in unit sales in Colombia.  In Colombia, we sold 9,000 barrels (“BBLs”) at an average gross price of $73.47 in 2010, compared to 11,000 BBLs at an average gross price of $40.26 in 2009.  In the United States, we sold 976 BBLs at an average gross price of $72.24 in 2010 compared to 1,282 BBLs at an average gross price of $44.22 in 2009.

Pipeline sales

Pipeline sales were $107,293, a decrease of $805,217, or 88.2% in 2010 compared to $912,510 in 2009 due to a substantial decrease in the number of barrels transported to approximately 0.67 million BBLs (our share was approximately 63,000 BBLs) in 2010 from 5.31 million BBLs (our share was approximately 499,000 BBLs) in 2009.    Beginning in early 2010, the ODC Pipeline has been operating close to full capacity, and during the second quarter of 2010, the pipeline operated at full capacity.  This has severely restricted our ability to transport oil over our pipeline.  Unless conditions improve with the ODC Pipeline, or additional pipeline are built, we anticipate that pipeline sales will either remain at zero or at least be significantly below the 2009 levels.

Total revenues

Total revenues were $799,111, a decrease of $576,885, or 41.9% in 2010 compared to $1,375,996 in 2009.  Oil sales accounted for 86.6% and 33.7% of total revenues in 2010 and 2009, respectively.

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Production

	2010				2009				Increase/(Decrease)
	Net Barrels		% of Total		Net Barrels		% of Total		Barrels			%
Colombia		9,528		90.7%		11,998		90.3%		(2,470	)		-20.6%
United States		976		9.3%		1,282		9.7%		(306	)		-23.9%
Total		10,504		100.0%		13,280		100.0%		(2,776	)		-20.9%

Production, net of royalties, was 10,504 BBLs, a decrease of 2,776 BBLs, or 20.9% in 2010 compared to 13,280 BBLs in 2009 primarily due to production decreases in Colombia.  Colombia production accounted for 90.7% and 90.3% of total production in 2010 and 2009, respectively.

Operating costs and expenses

	2010				2009				Change
	Amount		Percentage		Amount		Percentage		Amount			Percentage
Operating expenses
Operating expenses	$	289,013		36.2%	$	431,109		31.3%	$	(142,096	)		-33.0%
General & administrative expenses		1,632,345		204.3%		1,075,111		78.1%		557,234			51.8%
Asset impairment		—		0.0%		1,724,473		125.3%		(1,724,473	)		N/A
Depreciation and depletion		177,407		22.2%		178,870		13.0%		(1,463	)		-0.8%
Stock based compensation expense		—		0.0%		55,493		4.0%		(55,493	)		-100.0%
Total Operating costs and expenses	$	2,098,765		262.6%	$	3,465,056		251.8%	$	(1,366,291	)		-39.4%

Operating expenses

Operating expenses were $289,013 in 2010, a $142,096 decrease or 33.0%, compared to $431,109 in 2009.  The decrease is due primarily to a decrease in operating costs in Colombia, consistent with production decreases.  Operating expenses as a percentage of total revenues increased to 36.2% in 2010 from 31.3% in 2009 as the decrease in revenues exceeded the decrease in operating expenses.

General and administrative expenses

General and administrative expenses were $1,632,345 in 2010, a $557,234 increase or 51.8%, compared to $1,075,111 in 2009.  The increase is primarily due to $860,937 of Colombian equity taxes which were recorded in 2010, as more fully described in footnote 7 above.  Excluding the Colombian equity taxes, general and administrative expenses would have been $771,408 in 2010, a $303,703 decrease or 28.2%, compared to 2009, due primarily to a reduction in payroll costs in 2010 as compared to 2009 and lower general and administrative expenses in Colombia.  General and administrative expenses as a percentage of total revenues increased to 204.3% in 2010 from 78.1% in 2009.  Excluding the Colombian equity tax, general and administrative expenses as a percentage of total revenues would have been 96.5% due to the reduction in revenues.

Asset impairment

No impairment charge was recorded in 2010.  We recorded an asset impairment charge of $1,724,473 in 2009 relating to our first well at Rosablanca as we found no producible hydrocarbons.

Depreciation and depletion

Depreciation and depletion were $177,407 in 2010 and $178,870 in 2009.

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Stock based compensation expense

We recorded no stock based compensation expense in 2010.  Stock based compensation in 2009 consisted primarily of the value of shares issued to consultants.  All shares were valued based on the stock price at the date of issuance.

Loss from operations

Loss from operations was $1,299,654 and $2,089,060 in 2010 and 2009, respectively.   Loss from operations improved by $789,406 due primarily to the $1,724,473 asset impairment charge in 2009 compared to zero in 2010, the $142,096 decrease in operating expenses, offset by the $576,885 decrease in revenues in 2010 compared to 2009 and the $557,234 increase in general and administrative expenses in 2010 compared to 2009.

Interest income, net

Net interest income was $1,149 in 2010 compared to net interest income of $21,766 in 2009, due to lower cash balances in 2010.

Provision for income taxes

Provision for income taxes was zero in 2010 and 2009 due to losses incurred since inception.

Net loss

Net loss was $1,298,505 and $2,067,294 in 2010 and 2009, respectively.   The $768,789 improvement in net loss is due primarily to the improvement in loss from operations in 2010 compared to 2009.

Foreign currency translation loss

Foreign currency translation loss was $130,964 in 2010 compared to a foreign currency translation gain of $53,300 in 2009.  The Colombian Peso to Dollar Exchange Rate averaged 1,950 and 2,112 in 2010 and 2009, respectively and was 1,928 and 2,145 at June 30, 2010 and June 30, 2009, respectively.

Comprehensive loss

Comprehensive loss was $1,429,469 in 2010 compared to $2,013,994 in 2009.  Comprehensive loss improved by $584,525 due primarily to the improvement in the net loss in 2010 compared to 2009.

Liquidity and capital resources

We had a working capital deficit of $95,260 compared to working capital of $1,095,699 at December 31, 2009.  The working capital deficit at June 30, 2010 consisted primarily of $894,020 of cash and cash equivalents and $91,797 of accounts receivable, offset by $917,602 of accrued expenses and $185,939 of accounts payable.  The working capital at December 31, 2009 consisted primarily of $1,174,989 of cash and cash equivalents and $156,211 of accounts receivable, offset by $221,398 of accounts payable and $47,948 of accrued expenses.  The large increase in accrued expenses in 2010 relates primarily to the Colombian equity tax as discussed in footnote 7.

At both June 30, 2010 and December 31, 2009, we had no debt on our balance sheet.  Since January 1, 2007, we have raised in excess of $6,000,000 in gross proceeds through various debt and equity financings, as well as partnership agreements.  We have used the majority of the net proceeds for costs related to our Rosablanca project in Colombia as well as for working capital purposes.

Net cash used in operating activities totaled $208,129 in 2010 compared to net cash provided by operating activities of $143,355 in 2009.  The major components of the net cash used by operating activities in 2010 were the net loss of $1,298,505, offset by the $834,196 increase in accounts payable and accrued expenses and the $177,407 of depreciation and depletion.  The major components of the net cash provided by operating activities in 2009 were the $1,724,473 asset impairment charges relating to our first well in Rosablanca and $178,870 of depreciation and depletion, offset by the net loss of $2,067,294.

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Net cash used in investing activities totaled $59,177 and $270,440 in 2010 and 2009, respectively.  Net cash used in investing activities in 2010 consisted entirely of investment in oil and gas properties.  Net cash used in investing activities in 2009 consisted primarily of $1,634,724 investments in oil and gas properties and $379,480 investment in Colombian trust accounts, offset by $881,523 received from LEC for the assignment of 50% of our Rosablanca concession and $797,483 received from Pacific as reimbursement for previously capitalized pipeline expenditures.

Net cash used in financing activities totaled $1,977 and $1,396 in 2010 and 2009, respectively and consisted of payments made on the promissory note.

Net operating revenues from our oil production are very sensitive to changes in the price of oil making 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 property in Oklahoma through independent contractors that operate producing wells for several small oil companies.  Pacific owns 90.6% of the Guaduas field in Colombia 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 are 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 Osage property in Oklahoma, we sold oil at prices ranging from $68.61 to $70.26 and $68.61 to $77.15 per barrel in the three and six months ended June 30, 2010, respectively, compared to $45.43 to $64.70 and $32.35 to $64.70 in the three and six months ended June 30, 2009, respectively.  In our Cimarrona property in Colombia, we sold oil at prices ranging from $63.32 to $78.70 and $63.32 to $78.70 per barrel in the three and six months ended June 30, 2010, respectively, compared to $42.71to $66.03 and $28.06 to $66.03 in the three and six months ended June 30, 2009, respectively.  The Colombian Peso to Dollar Exchange Rate averaged 1,952 and 2,224 in the three months ended June 30, 2010 and June 30, 2009, respectively and was 1,928 and 2,145 and at June 30, 2010 and June 30, 2009, respectively.  The exchange rate averaged 1,950 and 2,112 for the six months ended June 30, 2010 and June 30, 2009, 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. 19as amended, issued by the Financial Accounting Standards Board as codified by FASC ASC topic 932 “Extractive Activities – Oil and Gas” (“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.

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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.  In 2009, we recorded an impairment charge of $1,724,473 relating to our well in the Rosablanca concession as we found no producible hydrocarbons.

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, 2010, 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 “Asset Retirement and Environmental Obligations” (“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.

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.

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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, 2010, 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, 2010 is not effective.  Based on this assessment, management has determined that, as of June 30, 2010, 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 effect 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, 2010 that have materially affected, or are reasonable likely to materially affect, the Company’s internal control over financial reporting.

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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             Submission of Matters to a Vote of Security Holders

None

Item 5             Other Information

(a)  None

(b)  None

Item 6             Exhibits

See Exhibit Index attached hereto.

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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 10, 2010	By:	/s/ Kim Bradford
		Kim Bradford
		President and Chief Executive Officer

Date:  August 10, 2010	By:	/s/ Kim Bradford
		Kim Bradford Principal Financial Officer

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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

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