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, 2009





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
(Address of principal executive offices)

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





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





Yes x             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 5, 2009 was 46,359,775.









OSAGE EXPLORATION AND DEVELOPMENT, INC. AND SUBSIDIARY





TABLE OF CONTENTS




PagePART I – FINANCIAL INFORMATIONItem 1.
Financial Statements (unaudited)Consolidated Balance Sheets; June 30, 2009 and December 31, 2008
1Consolidated Statement of Operations; Three and Six Months ended June 30, 2009 and June 30, 2008
2Consolidated Statement of Cash Flows; Six Months ended June 30, 2009 andJune 30, 2008
3Notes to Consolidated Financial Statements
4Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
11Item 3.
Quantitative and Qualitative Disclosures about Market Risk
20Item 4.
Controls and Procedures
20PART II – OTHER INFORMATIONItem 1.
Legal Proceedings
21Item 1.A.
Risk Factors
21Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
21Item 3
Default upon Senior Securities
21Item 4
Submission of Matters to a Vote of Security Holders
22Item 5
Other Information
22Item 6
Exhibits
22Signatures
23





ii





PART I. FINANCIAL INFORMATION





Item 1. Financial Statements




OSAGE EXPLORATION AND DEVELOPMENT, INC.CONSOLIDATED BALANCE SHEETSAs of June 30, 2009 and December 31, 20082009


2008ASSETS

(unaudited)Current Assets:Cash and cash equivalents

$
936,762


$
988,508Colombian Trust Accounts (Note 4)


233,201



537,665Accounts Receivable


81,039



64,658Bank CD pledged for Letter of Credit (Note 6)


29,533



145,632Other Current Assets


267,187



110,986Prepaid Expenses


36,212



65,380Total Current Assets


1,583,934



1,912,829Property and Equipment, at cost (Note 2):Oil and gas properties and equipment


1,879,735



4,920,550Capitalized asset retirement costs


46,146



13,675Other property & equipment


46,222



46,2221,972,103



4,980,447Less: accumulated depletion, depreciation and amortization


(362,036
)


(183,166
)1,610,067



4,797,281Bank CD pledged for Bond


30,000



30,000Total Assets

$
3,224,001


$
6,740,110LIABILITIES AND STOCKHOLDERS' EQUITYCurrent Liabilities:Accounts payable

$
183,862


$
2,128,915Accrued Expenses


21,776



87,941Current Maturity of Promissory Note (Note 8)


3,416



3,572Total Current Liabilities


209,054



2,220,428Promissory Note, net of Current Maturity (Note 8)


2,043



3,283Liability for Asset Retirement Obligations (Note 12)


53,208



18,203Commitments and Contingencies (Note 9)Stockholders' Equity:Common stock, $0.0001 par value, 190,000,000 shares authorized; 46,959,775  and 40,959,775 shares issued and outstanding as of June 30, 2009 and December 31, 2008, respectively.


4,696



4,095Additional-Paid-in-Capital


11,804,013



11,336,613Deferred Compensation


-



(7,493
)Stock Purchase Notes Receivable


(142,500
)


(142,500
)Accumulated Deficit


(8,223,010
)


(6,155,716
)Accumulated Other Comprehensive Loss - Currency Translation (Loss)


(483,503
)


(536,803
)2,959,696



4,498,196Total Liabilities and Stockholders' Equity

$
3,224,001


$
6,740,110





The accompanying notes are an integral part of these consolidated financial statements.
 1




OSAGE EXPLORATION AND DEVELOPMENT, INC.CONSOLIDATED STATEMENTS OF OPERATIONSFor the Three and Six Months ended June 30, 2009 and June 30, 2008 (unaudited)Three Months ended June 30,


Six Months ended June 30,2009


2008


2009


2008Operating RevenuesOil Revenues

$
210,942


$
874,520


$
463,486


$
909,086Pipeline Revenues


420,983



206,807



912,510



206,807Total Operating Revenues


631,925



1,081,327



1,375,996



1,115,893Operating Costs and ExpensesOperating Expenses


227,600



353,233



431,109



371,655Asset Impairment


111,579



-



1,724,473



-Depreciation, Depletion and Accretion


92,236



61,528



178,870



64,261Stock Based Compensation Expense


18,000



849,930



55,493



1,531,860General and Administrative Expenses


529,047



378,702



1,075,111



777,311Total Operating Costs and Expenses


978,462



1,643,393



3,465,056



2,745,087Operating (Loss)


(346,537
)


(562,066
)


(2,089,060
)


(1,629,194
)Other Income (Expenses):Interest Income


7,916



51,562



24,442



78,361Interest Expense


(1,342
)


(250,566
)


(2,676
)


(501,134
)Other


-



4,529



-



4,529(Loss) before Income Taxes


(339,963
)


(756,541
)


(2,067,294
)


(2,047,438
)Provision for Income Taxes


-



83,670



-



83,670Net (Loss)


(339,963
)


(840,211
)


(2,067,294
)


(2,131,108
)Other Comprehensive Income/(Loss), net of tax:Foreign Currency Translation Adjustment


360,231



(133,562
)


53,300



(8,591
)Other Comprehensive Income/ (Loss)


360,231



(133,562
)


53,300



(8,591
)Comprehensive Income/(Loss)

$
20,269


$
(973,773
)

$
(2,013,994
)

$
(2,139,699
)Earnings per Share Date:Basic and Diluted Net Loss

$
(0.01
)

$
(0.02
)

$
(0.04
)

$
(0.06
)Other Comprehensive Income/ (Loss)

$
0.01


$
(0.00
)

$
0.00


$
(0.00
)Comprehensive Income/Loss

$
0.00


$
0.02


$
(0.04
)

$
(0.06
)Weighted average number of common share and common share equivalents used to compute basic and dilluted Loss per Share


46,504,830



38,776,259



46,359,775



37,368,017
  
 The accompanying notes are an integral part of these consolidated financial statements.


2




OSAGE EXPLORATION AND DEVELOPMENT, INC.CONSOLIDATED STATEMENTS OF CASH FLOWSFor the Six Months Ended June 30, 2009 and June 30, 2008 (unaudited)2009


2008Cash flows from Operating Activities:Net (Loss)

$
(2,067,294
)

$
(2,131,108
)Adjustments to reconcile net (loss) to net cash provided/(used) by operating activites:Asset Impairment


1,724,473



-Beneficial Conversion of Convertible Debenture


-



433,580Stock Based Compensation


7,493



1,363,860Shares issued for services


48,000



168,000Accretion of Asset Retirment Obligation


35,005



828Amortization of Deferred Financing Costs


-



22,344Provision for depletion, depreciation amortization and valuation allowance


178,870



64,261Changes in operating assets and liabitlies:(Increase) in accounts receivable


(16,381
)


(422,936
)Decrease/(Increase) in other current assets


109,296



(141,794
)Decrease in prepaid expenses


30,859



47,096Increase in accounts payable and accrued expenses


93,034



73,019Net cash provided/(used) by operating activities


143,355



(522,850
)Cash flows from Investing Activities:Cash acquired with Cimarrona Acquisition


-



480,793Increase in Asset Retirement Obligation


(32,471
)


-Pipeline Reimbursement 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 assignment of 50% of Rosablanca


881,523



-Investments in Oil & Gas Properties


(1,634,724
)


(2,179
)Return of deposit made on Oil & Gas Property


-



140,000Purchase of Non Oil & Gas property


-



(36,400
)Interest earned on Bank CD pledged for Letter of Credit


(1,535
)


3,043Interest earned on Colombian Bonds


-



66,863Investment in Colombian Trust Account


(379,480
)


2,619Net cash provided/(used) by investing activities


(270,440
)


654,739Cash flows from Financing Activities:Proceeds from payment on Stock Purchase Notes Receivable


-



167,375Payments on Promissory Notes


(1,396
)


(1,729
)Net cash provided/(used) by financing activities


(1,396
)


165,646Effect of exchange rate on cash and cash equivalents


76,735



(8,591
)Net increase (decrease) in cash and cash equivalents


(51,746
)


288,944Cash and Cash equivalents beginning of period


988,508



689,545Cash and Cash equivalents end of period

$
936,762


$
978,489SUPPLEMENTAL CASH FLOW INFORMATION:Cash Payment for Interest


142



66,726Cash Payment for Income Taxes


-



-Non-Cash Transactions:Forgiveness of accounts payable by Lewis Energy Corporation


1,985,043Forgiveness of Joint Operating Account Liabilities by Pacific Rubiales Energy Corp.


799,007Issuance of Shares to Lewis Energy Corporation


420,000Shares and Warrants issued in connection with Cimarrona acquisition






2,128,845Issuance of Shares for Services


48,000



168,000


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


3


OSAGE EXPLORATION AND DEVELOPMENT, INC. AND SUBSIDIARIES


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


June 30, 2009 (unaudited)





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 2008 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.





The Company incurred significant losses and negative cash flow in the last three years as well as the six months ended June 30, 2009 and has an accumulated deficit of $8,223,010 at June 30, 2009 and $6,155,716 (audited) at December 31, 2008.  Substantial portions of the losses are attributable to asset
impairment charges, stock based compensation expense, professional fees and interest expense.  The Company's operating plans require additional funds that may take the form of debt or equity financings. There can be 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) increasing our current production, (b) controlling overhead and expenses and (c) raising additional capital and/or obtaining
financing.





There can be 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 can be 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 December 2007, the FASB issued SFAS No. 160, "Noncontrolling Interests in Consolidated Financial Statements", which is an amendment of Accounting Research Bulletin ("ARB") No. 51. SFAS 160 clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be
reported as equity in the consolidated financial statements. SFAS 160 changes the way the consolidated income statement is presented, thus requiring consolidated net income to be reported at amounts that include the amounts attributable to both parent and the noncontrolling interest. SFAS 160 is effective for the fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Based on current conditions, the Company does not expect the adoption of SFAS 160 to have a significant
impact on its results of operations or financial position.




4




In March 2008, the FASB issued SFAS No. 161, "Disclosures about Derivative Instruments and Hedging Activities an amendment of FASB Statement No. 133." SFAS 161 changes the disclosure requirements for derivative instruments and hedging activities. Entities are required to provide enhanced disclosures about (a) how
and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity's financial position, financial performance, and cash flows. Based on current conditions, the Company does not expect the adoption of SFAS 161 to have a significant impact on its results of operations or financial position.





In May 2008, the FASB issued SFAS No. 162, "The Hierarchy of Generally Accepted Accounting Principles." SFAS 162 identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity
with generally accepted accounting principles (GAAP) in the United States (the GAAP hierarchy). SFAS 162 did not have an 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." The scope of SFAS 163 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, SFAS 163 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), SFAS 163 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." SFAS 163 will not have an impact on the Company's financial statements.





In May 2009, the FASB issued FASB No. 165, “Subsequent Events” (“SFAS 165”). SFAS 165 establishes general standards of accounting for disclosing events that occur after the balance sheet date but before financial statements
are issued or are available to be issued. It requires the disclosure of the date through which an entity has evaluated subsequent events and the basis for selecting that date, that is, whether that date represents the date the financial statements were issued or were available to be issued. SFAS 165 is effective for interim or annual financial periods ending after June 15, 2009. The adoption of the standard will not have a material impact on the Company.





In June 2009, the FASB issued FASB No. 166, “Accounting for Transfers of Financial Assets - an amendment of FASB Statement No. 140” (“SFAS 166”). SFAS 166 requires additional disclosures about the transfer and derecognition
of financial assets and eliminates the concept of qualifying special-purpose entities under SFAS 140. SFAS 166 is effective for fiscal years beginning after November 15, 2009. The adoption of the standard will 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”, 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. Earlier application is
prohibited. The Company is currently assessing the impact of the adoption of SFAS 167 on the Company’s financial condition, results of operations and cash flows.




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” (FAS 168).
In addition in June 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 FAS 168 and ASU 2009-1 recognize the FASB Accounting Standards Codificationas
the source of authoritative U.S. generally accepted accounting principles to be utilized by nongovernmental entities. FAS 168 and ASU 2009-1 are effective for interim and annual periods ending after September 15, 2009. The adoption of this pronouncement is not expected to have a material effect on the Company’s financial statements.





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.





Income Tax





The Company adopted the provisions of FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes, on January 1, 2008.  As a result of the implementation of FIN 48, the Company made a comprehensive review of its portfolio of tax positions in accordance with recognition standards established by
FIN 48.  As a result of the implementation of Interpretation 48, 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.




We did not have a provision for income taxes for 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.  In 2008, we recorded a
tax provision of $83,270 relating entirely to our Cimarrona operations in Colombia which we acquired on April 1, 2008.  We eliminated this amount when we computed our full year 2008 provision due to the history of operating losses that existed in Cimarrona prior to us acquiring it.




2. OIL AND GAS PROPERTIES





Oil and gas properties consisted of the following as of June 30, 2009 and December 31, 2008:





2009


2008Properties subject to amortization

$
1,872,160


$
2,239,193Properties not subject to amortization


7,574



2,681,357Capitalized asset retirement costs


46,146



13,6751,925,880



4,934,225Accumulated depreciation and depletion


(338,066
)


(143,290
)Oil and as Properties, Net

$
1,587,814


$
4,790,935





The significant decrease in oil and gas properties relate primarily to (i) to the assignment of 50% of Rosablanca to Lewis Energy Corporation as more fully described in footnote 10 and the asset impairment charge to write down the value of all costs relating to the first well in Rosablanca and (ii) a transaction
with Pacific Rubiales Energy Corp. (“Pacific”), the operator of the pipeline and 90.4% owner of the Guaduas field in Colombia Pacific whereby Pacific reimbursed us for certain costs relating to the pipeline as well as adjusted the amount owed to them under our joint operating agreement, which were originally included as capitalized costs of the pipeline.  No gain or loss was recognized from this transaction.




6


3. GEOGRAPHICAL INFORMATION





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





Revenues for the


Revenues for theQuarter ended June 30, 2009


Quarter ended June 30, 2008Amount


% of Total


Amount


% of TotalColombia

$
606,800



96.0
%

$
990,512



91.6
%United States


25,125



4.0
%


90,815



8.4
%Total

$
631,925



100.0
%

$
1,081,327



100.0
%Revenues for the


Revenues for theSix Months ended June 30, 2009


Six Months ended June 30, 2008Amount


% of Total


Amount


% of TotalColombia

$
1,333,055



96.9
%

$
990,512



88.8
%United States


42,490



3.1
%


125,381



11.2
%Total

$
1,375,545



100.0
%

$
1,115,893



100.0
%Long Lived Assets at


Long Lived Assets atJune 30, 2009


June 30, 2008Colombia

$
1,441,640



89.5
%

$
2,442,219



94.4
%United States


168,427



10.5
%


145,227



5.6
%Total

$
1,610,067



100.0
%

$
2,587,446



100.0
%





4. COLOMBIAN TRUST ACCOUNTS




In June 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 mile Rosablanca concession in Colombia awarded by the Agencia Nacional de Hidrocarburos
(“ANH”) to Gold in June 2007.  In August 2007, we (i) paid $1,200,000 to Gold representing the funds Gold previously issued to a trust established by the ANH to use for drilling the first well for 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 did.  As of June
30, 2009, we had a balance of $1,474 in this trust account.




Under the terms of the concession agreement with the ANH, we are required to perform six twelve-month phases.  The ANH concession shall remain in effect as long as we meet our timely obligations to complete each phase that we present to the ANH.  We already performed the first phase which was
to drill the first well.  Each phase requires 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 new trust account for $790,000, of which our share was initially $395,000, later reduced to $197,500 upon the signing of the Lewis Energy Colombia, Inc., (“LEC”) transaction as further described in Footnote 10.  Phase 2 also required the issuance of a letter of credit for $110,000, of which
our share was initially $55,000, later reduced to $27,500 upon signing of the LEC transaction and obligated us to perform certain seismic work.  As of June 30, 2009, we had a balance of $231,727 in the trust account to be used for Phase 2.  Each of phases 3, 4, 5 and 6 requires the funding of separate trusts account of $1,200,000, of which our share will be $300,000 and an issuance of a letter of credit of $144,000, of which our share will be $36,000 and the drilling of an additional well
in each phase.




7




5. DEPOSITS




In November 2007, we entered into an agreement to purchase out of bankruptcy a working interest in an and gas leasehold and producing wellbore in Louisiana for a purchase price of $1,400,000.  Upon the signing of the agreement, we placed a deposit totaling 10% of the total purchase price, or $140,000.  The
bankruptcy court did not pursue the sale and we received our deposit of $140,000 back on March 1, 2008.  We have no further obligations for this property.





6. BANK CD PLEDGED FOR LETTER OF CREDIT





In August 2007, we placed $144,000 in a certificate of deposit (“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 June 2008, we received an extension from the ANH until December 26, 2008 to drill our first well.  Accordingly,
in December 2008, the CD was extended until March 25, 2009.  As we completed our obligation on the first well by December 26, 2008, the letter of credit expired on March 25, 2009 and we redeemed the CD at that time.  Accordingly, the balance of this CD at June 30, 2009 was zero.





In March 2009, we placed the equivalent of $55,000 in a CD with a bank in Colombia as collateral for the $110,000 letter of credit required by the ANH for Phase 2.  LEC reimbursed us $27,500 for this CD as more fully described in footnote 4 above.  The balance of this CD at June 30, 2009 was $29,533.





7. UNSECURED CONVERTIBLE PROMISSORY NOTE





In July 2007, we issued a $1,100,000 unsecured convertible promissory note (“Unsecured Convertible Promissory Note”) to one institutional investor for gross proceeds of $1,100,000.  The Unsecured Convertible Promissory Note matured September 30, 2008, had an 8% interest rate, payable in cash
quarterly, and was convertible, in whole or in part, into units, with each unit (“Unit”) priced at $1.00 and consisting of one share of Common Stock and one warrant, exercisable at $1.25 per share maturing three years from issuance.  We had the option to prepay the Unsecured Convertible Promissory Note at any time prior to maturity with no penalty.   We had the option, but only at maturity, to repay the Unsecured Convertible Promissory Note in Units.  At September
30, 2008, we elected to repay in full the Unsecured Convertible Promissory note by issuing 1,100,000 Units.  As such, the balance of the Unsecured Convertible Promissory Note at June 30, 2009 and December 31, 2008 (audited) was zero.  Pursuant to EITF 98-5, "Accounting for Convertible Securities with Beneficial Conversion Features or Contingently Adjustable Conversion Ratios" and EITF 00-27, “Application of Issue No. 98-5 in Certain Convertible Instruments,” we recorded $1,067,274
upon the issuance of the Unsecured Convertible Promissory Note attributable to the beneficial conversion feature as additional paid in capital.  The discount was amortized using the effective interest rate method over the term of the indebtedness.





8. 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%, and has monthly principal
and interest payments totaling $366.  As of June 30, 2009, the interest rate on the Promissory Note was 4.25%.





The following table summarizes the balance of the Promissory Note at June 30, 2009:





Promissory Note Outstanding at June 30, 2009

$
5,459Less Current Portion

3,416$
2,043




8


9. COMMITMENTS AND CONTINGENCIES





The concession with the ANH shall remain in effect for up to 24 years as long as we meet our timely obligations to complete the requirements of each phase that we present to the ANH.  Each of phases 3, 4, 5 and 6 requires the funding of separate a trust account in the amount of $1,200,000, of which our
share will be $300,000, the issuance of a letter of credit of $144,000, of which our share will be $35,000 and the drilling of an additional well in each phase.  We may, after completing our obligations for the current phase and prior to the beginning of the next phase, decline to pursue the concession at which point, we would lose the concession but would not have any obligations for any future phases





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 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, 2009, 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 as of June 30, 2009 under operating leases are as follows by year:





Year

Amount2010


38,3702011


27,459Totals

$
65,829
  Rental expense charged to operations totaled $13,332 and $26,428 for the quarter and six months ended June 30, 2009, respectively.  Rental expense charged to operations totaled $9,571 and $19,653 for the quarter and six months ended June 30, 2008, 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.




9


10. EQUITY TRANSACTIONS





Cimarrona Acquisition


In February 2008, we entered into an letter of intent and issued a $100,000 deposit to acquire a minority position in certain producing oil and gas assets in Colombia.  On April 8, 2008, we entered into a membership interest purchase agreement (the “Purchase Agreement”) with Sunstone Corporation
(“Sunstone”) pursuant to which the Company 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 cover 30,665 acres in the Middle Magdalena Valley in Colombia.  The Purchase Agreement was effective as of April 1, 2008.  The
purchase price consisted of 2,750,000 shares of the Company’s Common Stock and a warrant to purchase 1,125,000 shares of the Company’s Common Stock exercisable at $1.25 per share and expiring April 8, 2013.  The $100,000 deposit was returned to the Company in conjunction with closing of the transaction.  In addition, the Company issued 50,000 shares of Common Stock to Energy Capital Solutions, LP for their role as financial advisor in the transaction and $22,500 to an unaffiliated
individual as a finder’s fee.





Lewis Energy Colombia, Inc.


In March 2009, we entered into an agreement (the “LEC Agreement”) with Lewis Energy Colombia, Inc. (“LEC”), whereby LEC has 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 is 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.”  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.  As a result of the transaction, we recognized no gain or loss on the assignment of our interest.  On March 23, 2009, we announced we completed testing on the first well without finding producible hydrocarbons in any of the
zones evaluated.





11. MAJOR CUSTOMERS





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




Quarter ended June 30, 2009


Quarter ended June 30, 2008Amount


% of Total


Amount


% of TotalPacific

$
420,983



66.6
%

$
218,583



20.2
%HOCOL


185,817



29.4
%


771,929



71.4
%Sunoco


25,125



4.0
%


90,815



8.4
%Total

$
631,925



100.0
%

$
1,081,327



100.0
%Six Months ended June 30, 2009


Six Months ended June 30, 2008Amount


% of Total


Amount


% of TotalPacific

$
912,350



66.3
%

$
218,583



19.6
%HOCOL


420,746



30.6
%


771,929



69.2
%Sunoco


42,900



3.1
%


125,381



11.2
%Total

$
1,375,996



100.0
%

$
1,115,893



100.0
%
  Oil Revenues are derived from HOCOL, S.A. (“HOCOL”) and Sunoco, Inc. (“Sunoco”), while pipeline revenues are derived from Pacific Rubiales Energy Corp. (“Pacific”).





12. 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.




10


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, 2009


June 30, 2008Colombia


United States


Combined


Colombia


United States


CombinedBeginning Balance

$
-


$
18,203


$
18,203


$
-


$
16,547


$
16,547Incurred during the period






-



-



-



-



-Additions for new wells


32,471



-



32,471



-



-



-Accretion expense


1,624



910



2,534



-



414



414Ending Balance

$
34,095


$
19,113


$
53,208


$
-


$
16,961


$
16,961
  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, international and political uncertainty, fluctuations in exchange rates, 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.





In June 2007, we entered into the Agreement with Gold and Empesa, whereby we farmed-in to the approximately 165 square mile Rosablanca concession in Colombia awarded by the ANH to Gold in June, 2007.  Our decision to pursue the Rosablanca project was based on the seismic data generated by the ANH that revealed
multiple target opportunities.  Under the Agreement, we are considered the operators of the concession and are obligated to pay all costs associated with drilling and testing of the first well on the Rosablanca project.  Revenues generated from the first well were to be allocated 50% to us, 40% to Gold and 10% to Empesa.  In March 2009, we entered into 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 the Rosablanca.  In addition, LEC is entitled to receive an amount equal to 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.”  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 we completed testing on the first well without finding producible hydrocarbons in any of the zones evaluated.  As
a result of the transaction, we recognized no gain or loss on the assignment of our interest.




11




In August 2007, we (i) paid $1,200,000 to Gold representing the funds Gold previously issued to a trust account established by the ANH to use for drilling the first well for the Rosablanaca concession and (ii) issued a letter of credit in the amount 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 have the right to explore for up to six twelve-months phases.  The exploitation phase of the concession with the ANH shall remain in effect for up to 24 years as long as we meet our timely obligations to drill each well that we present to the ANH. We already performed the first phase which
was to drill the first well.  Each phase will require 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 $27,500 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.  Each
of phases 3, 4, 5 and 6 requires the funding of a separate trust account of  $1,200,000, of which our share will be $300,000, an issuance of a letter of credit in the amount of $144,000, of which our share will be $36,000 and the drilling of an additional well in each phase.  We may, after completing our obligations for the current phase and prior to the beginning of the next phase, decline to pursue the concession, at which point we would lose the concession but would not have any obligations
for any future phases.  The royalty rate under this ANH contract is 8% for up to 5,000 barrels per day, increasing to 25% if production exceeds 600,000 barrels per day.  On March 23, 2009, we announced that we have completed testing on the first well without finding producible hydrocarbons in any of the zones evaluated.




In February 2008, we entered into a letter of intent and issued a $100,000 deposit to acquire a minority position in certain producing oil and gas assets in Colombia.  On April 8, 2008, we entered into (the Purchase Agreement with Sunstone pursuant to which we acquired from Sunstone 100% of the membership
interests in Cimarrona LLC, 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 in excess of 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 2009 which would effectively reduce the cash flows generated by the property 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 April 2009, Pacific reimbursed us $797,483 and reduced the amount owed to them under our joint operating agreement by $799,007 relating to certain disputes we had with Pacific regarding a blending facility that they built to in conjunction with the pipeline.  These amounts were originally included as
capitalized costs of the pipeline.  No gain or loss was recognized from this transaction.





We anticipate we will need to raise at least $1,000,000 to provide for requirements for the next twelve months including costs to complete phase 2 and fund the trust account and letter of credit for phase 3 of Rosablanca.  If we are unable to raise the entire sum and cannot fulfill our obligations under
the Rosablanca concession, we may lose the concession and our ability to participate in other Colombian projects.  At present, the revenues generated from Cimarrona and Oklahoma properties are only sufficient to cover field operating expenses and a portion of our overhead.




12


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 in the Osage and Cimarrona properties and (c) controlling overhead and expenses.





There can be 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, 2009 compared to Three Months ended June 30, 2008


Revenues and Production





2009


2008


ChangeAmount


Percentage


Amount


Percentage


Amount


PercentageOil Revenues

$
210,942



33.4
%

$
874,520



80.9
%

$
(663,578
)


-75.9
%Pipeline Revenues


420,983



66.6
%


206,807



19.1
%


214,176



103.6
%Total Revenues


631,925



100.0
%


1,081,327



100.0
%


(449,402
)


-41.6
%





Oil Revenues





Oil Revenues were $210,942, a decrease of $663,578, or 75.9%, in 2009 compared to $874,520 in 2008.   The decrease is due primarily to a significant decrease in oil prices as well as a decrease in barrels sold in Colombia.  In Colombia, we sold 4,000 barrels (“BBLs”) at an average
price of $48.90 in 2009 compared to 7,000 BBLs at $115.47 in 2008.  In the United States, we sold 635 BBLs at an average price of $52.44 in 2009 compared to 985 BBLs at an average price of $122.49 in 2008.





Pipeline Revenues





Pipeline revenues were $420,983, an increase of $214,176, or 103.6%, in 2009 compared to $206,807 in 2008 due primarily to an increase in the number of barrels transported to approximately 2,600,000 BBLs (our share was approximately 244,000) BBLs in 2009 from approximately 1,570,000 (our share was approximately 148,000)
BBLs in 2008.





Total Revenues





Total revenues were $631,925, a decrease of $449,402, or 41.6%, in 2009 compared to $1,081,327 in 2008.  Pipeline revenues accounted for 66.6% and 19.1% of total revenues in 2009 and 2008, respectively.




13


Production


2009


2008


Increase/(Decrease)Net Barrels


% of Total


Net Barrels


% of Total


Barrels


%Colombia


5,853



90.2
%


5,949



85.8
%


(96
)


-1.6
%United States


635



9.8
%


985



14.2
%


(350
)


-35.5
%Total


6,488



100.0
%


6,934



100.0
%


(446
)


-6.4
%




Production, net of royalties, was 6,488, a decrease of 446 BBLs, or 6.4% in 2009 compared to 6,934 in 2008 as production decreased in both Colombia and the United States.  Colombia production accounted for 90.2% and 85.8% of total production in 2009 and 2008, respectively.  Production per day, net of royalties, was approximately
71 and 76 in 2009 and 2008, respectively.





Operating Costs and Expenses




2009


2008% of





% of


ChangeAmount


Revenues


Amount


Revenues


Amount


PercentageOperating Expenses

$
227,600



36.0
%

$
353,233



32.7
%

$
(125,633
)


-35.6
%Asset Impairment


111,579



17.7
%


-



0.0
%


111,579



N/AStock Based Compensation Expense


18,000



2.8
%


849,930



78.6
%


(831,930
)


-97.9
%Depreciation , Depletion and Accretion


92,236



14.6
%


61,528



5.7
%


30,708



49.9
%General & Administrative Expenses


529,047



83.7
%


378,702



35.0
%


150,345



39.7
%Total Operating Costs and Expenses

$
978,462



154.8
%

$
1,643,393



152.0
%

$
(664,932
)


-40.5
%


Operating Expenses





Our operating expenses were $227,600 and $353,233 in 2009 and 2008, respectively.  The decrease in operating expenses of $125,633, primarily related to decrease of operating expenses in our Cimarrona property in 2009 compared to 2008.  Operating expenses as a percentage of total revenues increased
to 36.0% in 2009 from 32.7% in 2008 due to the significant decline in revenues.





Asset Impairment





We recorded an asset impairment charge of $111,579 in 2009 relating to our first well at Rosablanca as we found no producible hydrocarbons.  No comparable impairment charge was recorded in 2008.





Stock Based Compensation Expense





Stock based compensation expense was $18,000 and $849,930 in 2009 and 2008.  2009 Stock based compensation expense was comprised of the value of shares issued to two consultants while 2008 stock based compensation consisted primarily for the amortization of the value of shares issued in November 2007 to
two employees which vested on January 2009.  All shares issued were valued based on the stock price at the date of issuance.





General and Administrative Expenses





General and administrative expenses were $529,047 in 2009, a $150,345 increase, or 39.7% increase, compared to $378,702 in 2008.  The increase is primarily attributable to increased compensations costs and increase in professional fees.  General and administrative expenses as a percentage of total
revenues increased to 83.7% in 2009 from 35.0% in 2008, primarily due to the significant decrease in revenues combined with an increase in general and administrative expenses.




14


Depreciation, depletion and accretion





Depreciation, depletion and accretion were $92,236 in 2009 compared to $61,528 in 2008.  Most of the depreciation and depletion expenses in 2009 and 2008 relate to our Cimarrona property.





Total Operating Costs and Expenses





Total Operating Costs and Expenses were $978,462 in 2009, a $664,931 decrease, or 40.5% decrease, compared to $1,643,393 in 2008 due primarily to a decrease in stock based compensation and operating expenses, offset by in increases in asset impairment and general and administrative expenses.  As a percentage
of total revenues, total operating costs and expenses were 154.8% and 152.0% in 2009 and 2008, respectively.





Operating Loss





Operating Loss was $346,537 in 2009, an improvement of $215,529 compared to an operating loss of $562,066 in 2008.  As a percentage of total revenues, operating loss was 54.8% and 52.0% in 2009 and 2008, respectively.





Other Income/(Expenses)





Total Other Income/(Expenses) consist primarily of interest expense and interest income.  Interest income was $7,916 and $51,562 in 2009 and 2008, respectively.  The decrease in interest income is due primarily to lower cash and trust balances as well as a decrease in interest rates in 2009 compared
to 2008.  Interest expense was $1,342 and $250,566 in 2009 and 2008, respectively.  2008 interest expense consisted primarily of the amortization of the beneficial conversion feature of the $1,100,000 Unsecured Convertible Promissory Note, which converted into shares of Common Stock in September 2008.





Net Loss





Net loss was $339,963 and $840,211 in 2009 and 2008, respectively.


Foreign Currency Translation Adjustment





Foreign currency translation gain was $360,231 in 2009 compared to a foreign currently translation loss of $133,562 in 2008.  The Colombian Peso to Dollar Exchange Rate averaged 2,224 and 1,768 in 2009 and 2008, respectively.  The exchange rate was 2,145 and 1,915 at June 30, 2009 and June 30,
2008, respectively.





Comprehensive Income/(Loss)





Comprehensive income was $20,269 in 2009 compared to a comprehensive loss of $973,773 in 2008.





Six Months ended June 30, 2009 compared to Six Months ended June 30, 2008


Revenues and Production





2009


2008


ChangeAmount


Percentage


Amount


Percentage


Amount


PercentageOil Revenues

$
463,486



33.7
%

$
909,086



81.5
%

$
(445,600
)


-49.0
%Pipeline Revenues


912,510



66.3
%


206,807



18.5
%


705,703



341.2
%Total Revenues


1,375,996



100.0
%


1,115,893



100.0
%


260,103



23.3
%




15




Oil Revenues





Oil revenues were $463,486, a decrease of $445,600, or 49.0%, in 2009 compared to $909,086 in 2008.   The decrease is due primarily to a significant decrease in oil prices, offset by an increase in barrels sold in Colombia as we acquired the Cimarrona property on April 1, 2008.  In Colombia,
we sold 11,000 BBLs at an average price of $40.26 in 2009 compared to 7,000 BBLs at $115.47 in 2008.  In the United States, we sold 1,282 BBLs at an average price of $44.42 in 2009 compared to 1,474 BBLs at an average price of $112.99 in 2008.





Pipeline Revenues





Pipeline revenues were $912,510, an increase of $705,703, or 341.2%, in 2009 compared to $206,807 in 2008 due primarily to the inclusion of the Cimarrona property for all of 2009 compared to only the first quarter of 2008.  The number of barrels transported was approximately 5,310,000 (our share was approximately
499,000) BBLs in 2009 compared to approximately 1,570,000 (our share was approximately 148,000) BBLS in 2008.





Total Revenues





Total revenues were $1,375,996, an increase of $260,103, or 23.3%, in 2009 compared to $1,115,893 in 2008.  Pipeline revenues accounted for 66.3% and 18.5% of total revenues in 2009 and 2008, respectively.





Production





2009


2008


Increase/(Decrease)Net Barrels


% of Total


Net Barrels


% of Total


Barrels


%Colombia


11,998



90.3
%


5,949



80.1
%


6,049



101.7
%United States


1,282



9.7
%


1,474



19.9
%


(192
)


-13.0
%Total


13,280



100.0
%


7,423



100.0
%


5,857



78.9
%





Production, net of royalties, was 13,280, an increase of 5,857 BBLs, or 78.9% in 2009 compared to 7,423 in 2008 primarily due to the inclusion of the Cimarrona property for all of 2009 compared to only the first quarter of 2008.   Colombia accounted for 90.3% and 80.1% of 2009 and 2008 production, respectively.  Production
per day, net of royalties, was approximately 73 and 41 in 2009 and 2008, respectively, primarily due to the inclusion of the Cimarrona property for all of 2009.





Operating Costs and Expenses





2009


2008% of





% of


ChangeAmount


Revenues


Amount


Revenues


Amount


PercentageOperating Expenses

$
431,109



31.3
%

$
371,655



33.3
%

$
59,454



16.0
%Asset Impairment


1,724,473



125.3
%


-



0.0
%


1,724,473



N/AStock Based Compensation Expense


55,493



4.0
%


1,531,860



137.3
%


(1,476,367
)


-96.4
%Depreciation , Depletion and Accretion


178,870



13.0
%


64,261



5.8
%


114,609



178.3
%General & Administrative Expenses


1,075,111



78.1
%


777,311



69.7
%


297,800



38.3
%Total Operating Costs and Expenses

$
3,465,056



251.8
%

$
2,745,087



246.0
%

$
719,969



26.2
%




Operating Expenses





Our operating expenses were $431,109 and $371,655 in 2008.  The increase in operating expenses primarily resulted from the inclusion of the Cimarrona property for all of 2009 compared to only the first quarter in 2008.  Operating expenses as a percentage of total revenues decreased to 31.3% in
2009 from 33.3% in 2008 as the increase in revenues exceeded the increase in operating expenses.





16





Asset Impairment





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.  No comparable impairment charge was recorded in 2008.





Stock Based Compensation Expense





Stock based compensation expense was $55,493 and $1,531,860 in 2009 and 2008.  2009 Stock based compensation expense was comprised of the value of shares issued to consultants while 2008 stock based compensation consisted primarily of the amortization of the value of shares issued in November 2007 to two
employees which vested on January 2009.  All shares issued were valued based on the stock price at the date of issuance.





General and Administrative Expenses





General and administrative expenses were $1,075,111 in 2009, a $297,800 increase, or 38.3% increase, compared to $777,311 in 2008.  The increase is primarily attributable to increased compensation costs as well as increased costs relating to Rosablanca and the inclusion of the Cimarrona property for all
of 2009 compared to just the first quarter of 2008.  General and administrative expenses as a percentage of total revenues increased to 78.1% in 2009 from 69.7% in 2008 as the increase in general and administrative expenses were greater than the increase in total revenues.





Depreciation, depletion and accretion





Depreciation, depletion and accretion were $178,870 in 2009 compared to $64,261 in 2008.  Most of the amortization relates to the Cimarrona property.





Total Operating Costs and Expenses





Total Operating Costs and Expenses were $3,465,056 in 2009, a $719,969 increase, or 26.2% increase, compared to $2,745,087 in 2008 due primarily to an increase in asset impairment and general and administrative expenses, offset by decreases in stock based compensation expense.  As a percentage of total
revenues, total operating costs and expenses were 251.8% and 246.0% in 2009 and 2008, respectively.





Operating Loss





Operating Loss was $2,098,060 in 2009 compared to $1,629,194 in 2008.  As a percentage of total revenues, operating loss was 151.8% and 146.0% in 2009 and 2008, respectively.





Other Income/(Expenses)





Interest income was $24,442 and $78,361 in 2009 and 2008, respectively.  The decrease in interest income is due primarily to lower cash and trust balances and a decrease in interest rates in 2009 compared to 2008.  Interest expense was $2,676 and $501,134 in 2009 and 2008, respectively.  2008
interest expense consisted primarily of the amortization of the beneficial conversion feature of the $1,100,000 Unsecured Convertible Promissory Note, which converted into shares of Common Stock in September 2008.





Net Loss





Net loss was $2,067,294 and $2,131,108 in 2009 and 2008, respectively.


Foreign Currency Translation





Foreign currency translation gain was $53,300 in 2009 compared to a foreign currently translation loss of $8,591 in 2008.  The Colombian Peso to Dollar Exchange Rate averaged 2,063 and 1,838 in 2009 and 2008.




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Liquidity and Capital Resources





We had a working capital of $1,374,880 at June 30, 2009, compared to a working capital deficit of $307,599 at December 31, 2008.  Working capital at June 30, 2009 consisted primarily of $936,762 of cash and cash equivalents, $267,187 of other current assets primarily consisting of amounts due from Pacific
from our joint operating account and $233,201 balance in the Colombian trust accounts, offset by $183,862 of accounts payable.





At both June 30, 2009 and December 31, 2008, 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 provided by operating activities totaled $143,355 in 2009 compared to net cash used by operating activities of $522,850 in 2008.  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.  The major components of the net cash used in operating activities in 2008 were the net loss of $2,131,108 and an increase of $422,936 in accounts receivable, offset by $1,363,860 stock based compensation and $433,580 amortization of beneficial conversion feature of the convertible debenture.





Net cash used by investing activities totaled $270,440 in 2009 compared to net cash provided by investing activities of $634,739.  Net cash used in investing activities in 2009 consisted primarily of $1,634,724 investments in oil and gas properties and the $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 investing activities in 2008, consisted primarily of the $480,793 of cash acquired with the Cimarrona acquisition and the return of $140,000 of a deposit made on an oil property.





Net cash used by financing activities totaled $1,396 in 2009 while net cash provided by financing activities totaled $165,646 in 2008 and consisted primarily of the $167,375 proceeds from payment on the stock purchase notes receivable.




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 through independent contractors that operate producing wells for several small oil companies.  Pacific Rubiales owns 90.6% of the Guaduas field and is its operator, while LEC owns 25% of the Rosablanca concession and is its 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.  Average price received by us for a barrel were $49.38 and $116.34 in the second quarters of 2009 and 2008, respectively and $40.70 and $115.04 for the six months ended June 30, 2009 and 2008, respectively.  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.




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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.  The Colombian Peso to Dollar Exchange Rate averaged 2,224 and 1,768 in the second quarter of 2009 and 2008, respectively
and was 2,145 and 1,915 at June 30, 2009 and June 30, 2008, respectively.  The exchange rate was 2,063 and 1,838 for the six months ended June 30, 2009 and June 30, 2008, 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.  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.  In 2009, we recorded an impairment charge of $1,724,473 relating to our first 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, 2009 and December 31, 2008, all of 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," 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.




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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.





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, 2009, 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, 2009 is not effective.  Based on this assessment, management has determined that, as of June 30, 2009, 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.





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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 and six months ended June 30, 2009 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) The following securities were issued during the fiscal quarter and not previously reported in a Quarterly Report on Form 10-Q of Current Report on Form 8-K





In June 2009, we issued a total of 600,000 shares of our Common Stock to two consultants.  The shares were valued at $18,000, or $0.03 per share, representing the closing stock price of the Common Stock at the date of grant.  The shares were issued pursuant to Section 4(2) of the Securities Act
of 1933 and Regulation D promulgated thereunder and a restrictive legend was placed thereon.





(b)  None





(c)  None





Item 3.
Default upon Senior Securities





None




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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 7, 2009
By:
/s/ Kim BradfordKim BradfordPresident and Chief Executive Officer


Date:  August 7, 2009
By:
/s/ Kim BradfordKim BradfordPrincipal 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.

Description3.1

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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