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 September 30, 2010





/  / 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/  /





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   /  /                             No/x /





Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company in Rule 12b-2 of the Exchange Act.





Large Accelerated Filer   /  /     Accelerated Filer   /  /


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





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


Yes   /  /                             No/x /





The number of outstanding shares of the registrant’s Common Stock, $0.0001 par value, as of November 8, 2010 was 46,649,775.


i


OSAGE EXPLORATION AND DEVELOPMENT, INC. AND SUBSIDIARY





TABLE OF CONTENTS


PagePART I – FINANCIAL INFORMATIONItem 1.
Financial Statements (unaudited)Consolidated Balance Sheets; September 30, 2010 and December 31, 2009
1Consolidated Statement of Operations and Comprehensive Loss; Three and Nine Months ended September 30, 2010 and September 30, 2009
2Consolidated Statement of Cash Flows; Nine Months ended September 30, 2010 and September 30, 2009
3Notes to Consolidated Financial Statements
4Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
10Item 3.
Quantitative and Qualitative Disclosures about Market Risk
19Item 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
21Item 5
Other Information
21Item 6
Exhibits
21Signatures

22
  ii


PART I. FINANCIAL INFORMATION





Item 1. Financial Statements


OSAGE EXPLORATION AND DEVELOMENT, INC.
 CONSOLIDATED BALANCE SHEETS


September 30,


December 31,2010


2009ASSETS

(unaudited)Current assets:Cash and cash equivalents

$
883,752


$
1,174,989Accounts receivable


9,868



156,211Prepaid expenses


59,292



37,380Total current assets


952,912



1,368,580Property and equipment, at cost:Oil and gas properties and equipment


2,401,666



2,174,793Capitalized asset retirement costs


46,146



46,146Other property & equipment


50,943



48,2052,498,755



2,269,144Less: accumulated depletion, depreciationand amortization


(824,689
)


(557,287
)Property and equipment, net


1,674,066



1,711,857Bank CD pledged for bond


30,000



30,000Total assets

$
2,656,978


$
3,110,437LIABILITIES AND STOCKHOLDERS' EQUITYCurrent liabilities:Accounts payable

$
190,374


$
221,398Accrued expenses


964,074



47,948Promissory note


552



3,535Total current liabilities


1,155,000



272,881Asset retirement obligations


57,245



55,742Total liabilities


1,212,245



328,623Commitments and contingencies (Note 7)Stockholders' equity:Common stock, $0.0001 par value, 190,000,000 shares authorized;


4,665



4,69646,649,775 and 46,959,775 shares issued and outstandingas of September 30, 2010 and December 31, 2009, respectivelyAdditional paid-in capital


11,795,844



11,804,013Stock purchase notes receivable


(95,000
)


(142,500
)Accumulated deficit


(10,031,550
)


(8,472,209
)Accumulated other comprehensive loss -currency translation loss


(229,226
)


(412,186
)Total stockholders' equity


1,444,733



2,781,814Total liabilities and stockholders' equity

$
2,656,978


$
3,110,437
 
 The accompanying notes are an integral part of these consolidated financial statements.
  1




OSAGE EXPLORATION AND DEVELOPMENT, INC.
 CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE LOSS
 (unaudited)
 Three Months Ended 
September 30,


Nine Months Ended 
September 30,2010


2009


2010


2009Operating revenues:Oil

$
376,555


$
397,819


$
1,068,373


$
861,305Pipeline


91,392



350,066



198,685



1,262,575Total operating revenues


467,947



747,885



1,267,058



2,123,880Operating costs and expenses:Operating


169,644



265,133



458,657



696,241General and administrative


429,877



449,520



2,062,222



1,521,308Asset impairment


-



183,205



-



1,903,686Depreciation and depletion


89,995



93,308



267,402



272,178Stock based compensation


39,300



-



39,300



55,493Total operating costs and expenses


728,816



991,166



2,827,581



4,448,906Loss from operations


(260,869
)


(243,281
)


(1,560,523
)


(2,325,026
)Other income/(expenses):Interest income


546



4,014



2,756



28,241Interest expense


(513
)


(1,333
)


(1,574
)


(4,009
)Loss before income taxes


(260,836
)


(240,600
)


(1,559,341
)


(2,300,794
)Provision for income taxes


-



-



-



-Net Loss

$
(260,836
)

$
(240,600
)

$
(1,559,341
)

$
(2,300,794
)Other comprehensive income:Foreign currency translation adjustment


75,015



29,840



182,959



230,328Comprehensive Loss

$
(185,821
)

$
(210,760
)

$
(1,376,382
)

$
(2,070,466
)Basic and diluted loss per share

$
(0.01
)

$
(0.01
)

$
(0.03
)

$
(0.05
)Weighted average number of common shareand common share equivalents used tocompute basic and dilluted loss per share


45,599,449



46,959,775



45,875,709



45,395,489
 
 The accompanying notes are an integral part of these consolidated financial statements.


2


OSAGE EXPLORATION AND DEVELOPMENT, INC.
 CONSOLIDATED STATEMENTS OF CASH FLOWS
 (unaudited)
 
 Nine Months Ended September 30,2010


2009Cash flows from operating activities:Net loss

$
(1,559,341
)

$
(2,300,794
)Adjustments to reconcile net loss to net cashprovided by (used in) operating activites:Asset impairment


-



1,903,686Stock based compensation


-



7,493Shares issued for services


39,300



48,000Accretion of asset retirment obligations


1,503



36,272Provision for depletion, depreciation and amortization


267,402



272,178Changes in operating assets and liabilities:Decrease/(increase) in accounts receivable


146,343



(13,900
)Decrease/(increase) in prepaid expenses


(21,912
)


121,525Increase in accounts payable and accrued expenses


885,103



447,347Net cash (used in)/provided by operating activities


(241,602
)


521,807Cash flows from investing activities:Increase in asset retirement obligations


-



(32,471
)Pipeline reimbursement by operator


154,289



797,483Investment in bank CD pledged for letter of credit


-



(49,453
)Maturity of bank CD pledged for letter of credit


-



145,632Proceeds from assignment of 50% of Rosablanca


-



912,164Investments in oil and gas properties


(120,051
)


(1,713,949
)Investment in non oil and gas assets


(2,738
)


-Interest earned on Bank CD pledged for letter of credit


-



(1,535
)Payments from Colombian trust account


-



(400,408
)Net cash provided by/ (used in) investing activities


31,500



(342,537
)Cash flows from financing activities:Payments on promissory note


(2,983
)


(2,348
)Net cash used in financing activities


(2,983
)


(2,348
)Effect of exchange rate on cash and cash equivalents


(78,152
)


45,529Net (decrease)/increase in cash and cash equivalents


(291,237
)


222,451Cash and Cash equivalents, beginning of period


1,174,989



988,508Cash and Cash equivalents, end of period

$
883,752


$
1,210,959SUPPLEMENTAL CASH FLOW INFORMATION:Cash payments for interest

$
71


$
208Cash payments for income taxes

$
-


$
-Non-cash transactions:Forgiveness of accounts payable by LEC

$
-


$
1,985,043Forgiveness of joint operating account by Pacific

$
-


$
799,007Issuance of shares to LEC in conjunction with the LEC Agreement

$
-


$
420,000Forgiveness of accounts payable by various vendors relating to Rosablanca

$
-


$
124,306Cancellation of shares for notes receivable

$
47,500


$
-
 
 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


September 30, 2010 (unaudited) and December 31, 2009





1. BASIS OF PRESENTATION





Osage Exploration and Development, Inc. (“Osage”, “We”, 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 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 in the last three years, as well as the nine months ended September 30, 2010 and has an accumulated deficit of $10,031,550 at September 30, 2010 and $8,472,209 (audited) at December 31, 2009.  Substantial portions of our losses are attributable to asset impairment charges, stock based compensation, professional fees, Colombian equity tax for 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” (“FAS 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 FAS 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. FAS 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.


4





In May 2009, the FASB issued FASB No. 165, “Subsequent Events” (“SFAS 165”), as codified by FASB ASC topic 855(“ASC 855”).  ASC 855 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. ASC 855 is effective for interim or annual financial periods ending after September 15, 2009. The adoption of ASC 855 did 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”), as codified by FASB ASC topic 860 (“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.





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





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 (“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.


5


2. OIL AND GAS PROPERTIES





Oil and gas properties consisted of the following as of September 30, 2010 and December 31, 2009:





2010


2009Oil and gas properties and equipment

$
2,401,666


$
2,174,793Capitalized asset retirement costs


46,146



46,146Accumulated depreciation and depletion


(785,169
)


(526,124
)Oil & Gas Properties, Net

$
1,662,643


$
1,694,815


Depreciation and depletion expense for oil and gas properties totaled $87,649 and $259,045 for the three and nine month ended September 30, 2010, respectively.   Depreciation and depletion expense for oil and gas properties totaled $89,751 and $261,679 for the three and nine months ended September 30, 2009, respectively.




3. GEOGRAPHICAL INFORMATION





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


Revenues for the Three


Revenues for the ThreeMonths ended September 30, 2010


Months ended September 30, 2009Amount


% of Total


Amount


% of TotalColombia

$
443,253



94.7
%

$
716,571



95.8
%United States


24,694



5.3
%


31,314



4.2
%Total

$
467,947



100.0
%

$
747,885



100.0
%
  Revenues for the Nine


Revenues for the NineMonths ended September 30, 2010


Months ended September 30, 2009Amount


% of Total


Amount


% of TotalColombia

$
1,188,620



93.8
%

$
2,049,626



96.5
%United States


78,438



6.2
%


74,254



3.5
%Total

$
1,267,058



100.0
%

$
2,123,880



100.0
%
  Long Lived Assets at


Long Lived Assets atSeptember 30, 2010


December 31, 2009Colombia

$
1,525,230



91.1
%

$
1,555,604



90.9
%United States


148,836



8.9
%


156,253



9.1
%Total

$
1,674,066



100.0
%

$
1,711,857



100.0
%




6





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 mile Rosablanca concession in Colombia awarded by the Agencia Nacional de Hidrocarburos (“ANH”) to Gold in June 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 the first well by December 26, 2008, which we did.  Under the terms of the concession agreement with the ANH, we are 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 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 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 September 30, 2010 and December 31, 2009.




5. 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 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 September 30, 2010 and December 31, 2009.




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 and then Lewis Energy Colombia, Inc. (“LEC”) reimbursed us $27,500 for its share, as more fully described in footnote 8 below.  Pursuant to the Termination Agreement described in footnote 8 below, we transferred the balance in this CD to Gold in the quarter ended September 30, 2009 and recorded an asset impairment charge of $31,419.  Accordingly, the balance of this CD was zero at September 30, 2010 and December 31, 2009.




6. 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 September 30, 2010 and December 31, 2009.





7. 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 matured October 27, 2010, had a variable interest rate of Prime plus 1.0% (4.25% as of September 30, 2010) and monthly principal and interest payments totaling $366.   The Promissory Note, which has now been paid off, had a balance of $552 and $3,535 at September 30, 2010 and December 31, 2009, respectively.





8. COMMITMENTS AND CONTINGENCIES





ENVIRONMENT





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


7





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 September 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 years 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 September 30, 2011 under operating leases are $15,691.





Rental expense charged to operations totaled $14,400 and $41,555 for the three and nine months ended September 30, 2010, respectively, and $13,332 and $39,760 for the three and nine months ended September 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 as, in the first quarter of 2010, we were notified by Division de Impuestos y Actuanas Nacionales (“DIAN”), the Colombian tax authorities, that Cimarrona owes this amount for taxes assessed on its equity value relating to its operations in 2001 and 2003 prior to its ownership by us.  In order to compute the equity value the equity tax is assessed upon, Cimarrona subtracted the cost of its non-producing wells in 2001 and 2003.  However, DIAN’s position is that as long as the field is productive, Cimarrona should not have subtracted the cost of the non-producing wells.  The Company is appealing DIAN’s decision but recorded an $860,937 expense, comprised of $407,238 for 2001 and $453,699 for the 2003.  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.





9. EQUITY TRANSACTIONS





Lewis Energy Colombia, Inc.


In March 2009, we entered into an agreement with Lewis Energy Colombia, Inc. (the “LEC Agreement”), whereby LEC agreed to provide $3,500,000 to drill the first well and become operator of Rosablanca 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 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 Lewis, whereby we and Lewis agreed to withdraw from the Rosablanca concession.


8





Notes Receivable


In January 2010 and June 2010, we cancelled 1,000,000 and 900,000 shares, respectively, relating to a note receivable of $47,500 collateralized by 1,900,000 shares.





10. MAJOR CUSTOMERS





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




Three Months ended


Three Months endedSeptember 30, 2010


September 30, 2009Amount


% of Total


Amount


% of TotalHOCOL

$
351,861



75.2
%

$
366,505



49.0
%Pacific


91,392



19.5
%

$
350,066



46.8
%Sunoco


24,694



5.3
%

$
31,314



4.2
%Total

$
467,947



100.0
%

$
747,885



100.00
%
  Nine Months ended


Nine Months endedSeptember 30, 2010


September 30, 2009Amount


% of Total


Amount


% of TotalHOCOL

$
989,935



78.1
%

$
787,051



37.1
%Pacific


198,685



15.7
%


1,262,575



59.4
%Sunoco


78,438



6.2
%


74,254



3.5
%Total

$
1,267,058



100.0
%

$
2,123,880



100.0
%





11. ASSET RETIREMENT OBLIGATIONS





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





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




September 30, 2010


December 31, 2009Colombia


United States


Combined


Colombia


United States


CombinedBeginning Balance

$
35,719


$
20,023


$
55,742


$
-


$
18,203


$
18,203Additions for new wells


-



-



-



32,471



-



32,471Accretion expense


-



1,503



1,503



3,248



1,820



5,068Ending Balance

$
35,719


$
21,526


$
57,245


$
35,719


$
20,023


$
55,742
 9
  12. INCOME TAX PROVISION





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.




Item 2.                                Management’s Discussion and Analysis of Financial Condition and Results of Operations.




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





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





In September 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.  Under the Agreement, we were considered the operators of the concession and were 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 with LEC whereby LEC agreed to 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 LEC 50% of our 50% interest in the Rosablanca concession and 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.    The LEC Agreements provides that 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.  In March 2009, we announced 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.


10





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 from the field 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.





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.





Results of Operations





Three Months ended September 30, 2010 compared to September 30, 2009


2010


2009


ChangeAmount


Percentage


Amount


Percentage


Amount


PercentageOil sales

$
376,555



80.5
%

$
397,819



53.2
%

$
(21,264
)


-5.3
%Pipeline Sales


91,392



19.5
%


350,066



46.8
%


(258,674
)


-73.9
%Total revenues

$
467,947



100.0
%

$
747,885



100.0
%

$
(279,938
)


-37.4
%


11




Oil Sales





Oil sales were $376,555, a decrease of $21,264, or 5.3%, in 2010 compared to $397,819 in 2009.   The decrease is primarily due to a decrease in unit sales in Colombia offset by increased oil prices received.  In Colombia, we sold 5,000 barrels (“BBLs”) at an average gross price of $72.92 in 2010, compared to 6,000 BBLs at an average gross price of $64.30 in 2009.  In the United States, we sold 447 BBLs at an average gross price of $71.90 in 2010 compared to 652 BBLs at an average gross price of $63.71 in 2009.





Pipeline Sales





Pipeline sales were $91,392, a decrease of $258,674, or 73.9%, in 2010 compared to $350,066 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 which has severely restricted our ability to transport oil over our pipeline.  Conditions appear to have improved, although we anticipate that pipeline sales will remain significantly below the 2009 levels.   In 2010, the pipeline transported approximately 0.56 million BBLs (our share was approximately 53,000) while in 2009, the pipeline transported approximately 2.23 million BBLs (our share was approximately 210,000).





Total Revenues





Total revenues were $467,947, a decrease of $279,938, or 37.4%, in 2010 compared to $747,885 in 2009.  Oil sales accounted for 80.5% and 53.2% of total revenues in 2010 and 2009, respectively.





Production




2010


2009


Increase/(Decrease)Net Barrels


% of Total


Net Barrels


% of Total


Barrels


%Colombia


4,220



90.0
%


5,190



88.8
%


(970
)


-18.7
%United States


467



10.0
%


652



11.2
%


(185
)


-28.4
%Total


4,687



100.0
%


5,842



100.0
%


(1,155
)


-19.8
%


Production, net of royalties, was 4,687 BBLs, a decrease of 1,155 BBLs, or 19.8%, in 2010 compared to 5,842 BBLs in 2009 primarily due to production decreases in Colombia.  Colombia production accounted for 90.0% and 88.8% of total production in 2010 and 2009, respectively.





Operating Costs and Expenses


2010


2009


ChangeAmount


Percentage


Amount


Percentage


Amount


PercentageOperating

$
169,644



36.3
%

$
265,133



35.5
%

$
(95,489
)


-36.0
%General & administrative


429,877



91.9
%


449,520



60.1
%


(19,643
)


-4.4
%Asset impairment


-



0.0
%


183,205



24.5
%


(183,205
)


N/ADepreciation and depletion


89,995



19.2
%


93,308



12.5
%


(3,313
)


-3.6
%Stock based compensation


39,300



8.4
%


-



0.0
%


39,300



N/ATotal operating costs and expenses

$
728,816



155.7
%

$
991,166



132.5
%

$
(262,350
)


-26.5
%Operating Loss


(260,869
)


-55.7
%


(243,281
)


-32.5
%


(17,588
)


7.2
%Other Income/(Expenses)


33



0.0
%


2,681



0.4
%


(2,648
)


(98.8
%)Net Loss


(260,836
)


-55.7
%


(240,600
)


-32.2
%


(20,236
)


(8.4
%)Comprehensive Loss

$
(185,821
)


-39.7
%

$
(210,760
)


28.2
%

$
24,939



11.8
%





12





Operating Expenses





Operating expenses were $169,644 in 2010, a $95,489 decrease, or 36.0%, compared to $265,133 in 2009.  The decrease is due primarily to a decrease in operating costs in Colombia from lower production and reduced pipeline activity.  Operating expenses as a percentage of total revenues increased to 36.3% in 2010 from 35.5% in 2009 as the decrease in revenues exceeded the decrease in operating expenses.





General and Administrative Expenses





General and administrative expenses were $429,877 in 2010, a $19,643 decrease, or 4.4%, compared to $449,520 in 2009.  The decrease is primarily due to lower general and administrative expenses in Colombia and a reduction in insurance expense in the U.S.  General and administrative expenses as a percentage of total revenues increased to 91.9% in 2010 from 60.1% 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 $183,205 in 2009 relating to our first well at Rosablanca as we found no producible hydrocarbons.





Stock Based Compensation Expense





Stock based compensation expense was $39,300 in 2010 compared to zero in 2009.  Stock based compensation in 2010 consisted of the value of shares issued to an officer, a new board member and a consultant.





Depreciation, depletion and accretion





Depreciation, depletion and accretion were $89,995 in 2010 and $93,308 in 2009.  The decrease in 2010 is due primarily to decreased depletion expense resulting from lower oil production.





Loss from Operations





Loss from operations was $260,869 and $243,281 in 2010 and 2009, respectively.   Loss from operations decreased by $17,588 due primarily to the $279,938 decrease in revenues in 2010 compared to 2009, offset by the $183,205 decrease in asset impairment charge in 2010 compared to 2009 and the $95,489 decrease in operating expenses in 2010 compared to 2009.





Interest Income, Net





Net interest income was $33 in 2010 compared to net interest income of $2,681 in 2009, due to lower cash balances and lower interest rates earned on money in banks in 2010 as compared to 2009.





Provision for Income Taxes





Provision for income taxes was zero in 2010 and 2009.





Net Loss





Net loss was $260,836 and $240,600 in 2010 and 2009, respectively.  The $20,236 decrease in net loss is due primarily to the $17,588 decrease in loss from operations in 2010 compared to 2009.





Foreign Currency Translation Gain





Foreign currency translation gain was $75,015 in 2010 compared to a foreign currency translation gain of $29,840 in 2009.  The Colombian Peso to Dollar Exchange Rate averaged 1,833 and 2,016 in 2010 and 2009, respectively and was 1,803 and 1,937 at September 30, 2010 and September 30, 2009, respectively.




13





Comprehensive Loss





Comprehensive loss was $185,821 in 2010 compared to a comprehensive loss of $210,760 in 2009.  Comprehensive loss improved by $24,939 due primarily to the $45,175 increase in foreign currency translation gain in 2010 compared to 2009.





Nine Months ended September 30, 2010 compared to September 30, 2009


Nine Months2010


2009


ChangeAmount


Percentage


Amount


Percentage


Amount


PercentageOil sales

$
1,068,373



84.3
%

$
861,305



40.6
%

$
207,068



24.0
%Pipeline sales


198,685



15.7
%


1,262,575



59.4
%


(1,063,890
)


-84.3
%Total revenues

$
1,267,058



100.0
%

$
2,123,880



100.0
%

$
(856,822
)


-40.3
%





Oil Sales





Oil sales were $1,068,373, an increase of $207,068, or 24.0%, in 2010 compared to $861,305 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 14,000 barrels (“BBLs”) at an average gross price of $73.27 in 2010, compared to 17,000 BBLs at an average gross price of $48.75 in 2009.  In the United States, we sold 1,442 BBLs at an average gross price of $72.13 in 2010 compared to 1,934 BBLs at an average gross price of $50.92 in 2009.





Pipeline Sales





Pipeline sales were $198,685, a decrease of $1,063,890, or 84.3%, in 2010 compared to $1,262,575 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 which has severely restricted our ability to transport oil over our pipeline.  Beginning in the third quarter of 2010, conditions appear to have improved, although we anticipate that pipeline sales will remain significantly below the 2009 levels.   In 2010, the pipeline transported approximately 1.23 million BBLs (our share was approximately 115,000) while in 2009, the pipeline transported approximately 7.54 million BBLs (our share was approximately 709,000).





Total Revenues





Total revenues were $1,267,058, a decrease of $856,822, or 40.3%, in 2010 compared to $2,123,880 in 2009.  Oil sales accounted for 84.3% and 40.6% of total revenues in 2010 and 2009, respectively.





Production


2010


2009


Increase/(Decrease)Net Barrels


% of Total


Net Barrels


% of Total


Barrels


%Colombia


13,748



90.5
%


17,188



89.9
%


(3,440
)


-20.0
%United States


1,442



9.5
%


1,934



10.1
%


(492
)


-25.4
%Total


15,190



100.0
%


19,122



100.0
%


(3,932
)


-20.6
%





Production, net of royalties, was 15,190 BBLs, a decrease of 3,392 BBLs, or 20.6% in 2010 compared to 19,122 BBLs in 2009 primarily due to production decreases in Colombia.  Colombia production accounted for 90.5% and 89.9% of total production in 2010 and 2009, respectively.




14





Operating Costs and Expenses




2010


2009


ChangeAmount


Percentage


Amount


Percentage


Amount


PercentageOperating

$
458,657



36.2
%

$
696,241



32.8
%

$
(237,584
)


-34.1
%General & administrative


2,062,222



162.8
%


1,521,308



71.6
%


540,914



35.6
%Asset impairment


-



0.0
%


1,903,686



89.6
%


(1,903,686
)


N/ADepreciation and depletion


267,402



21.1
%


272,178



12.8
%


(4,776
)


-1.8
%Stock based compensation


39,300



3.1
%


55,493



2.6
%


(16,193
)


-29.2
%Total Operating costs and expenses

$
2,827,581



223.2
%

$
4,448,906



209.5
%

$
(1,621,325
)


-36.4
%Operating Loss


(1,560,523
)


-123.2
%


(2,325,026
)


-109.5
%


764,503



-32.9
%Other lncome/(Expenses)


1,182



0.1
%


24,232



1.1
%


(23,050
)


-95.1
%Net Loss


(1,559,341
)


-123.1
%


(2,300,794
)


-108.3
%


741,453



-32.2
%Comprehensive Loss

$
(1,376,382
)


-108.6
%

$
(2,070,466
)


-97.5
%

$
694,084



-33.5
%




Operating Expenses





Operating expenses were $458,657 in 2010, a $237,584 decrease or 34.1%, compared to $696,241 in 2009.  The decrease is due primarily to a decrease in operating costs in Colombia from lower production and reduced pipeline activity Operating expenses as a percentage of total revenues increased to 36.2% in 2010 from 32.8% in 2009 as the decrease in revenues exceeded the decrease in operating expenses.





General and Administrative Expenses





General and administrative expenses were $2,062,222 in 2010, a $540,914 increase, or 35.6%, compared to $1,521,308 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 $1,201,285 in 2010, a $320,023 decrease or 26.6%, 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 162.8% in 2010 from 71.6% in 2009.  Excluding the Colombian equity tax, general and administrative expenses as a percentage of total revenues would have been 94.8%.





Asset Impairment





No impairment charge was recorded in 2010.  We recorded an asset impairment charge of $1,903,686 in 2009 relating to our first well at Rosablanca as we found no producible hydrocarbons.





Stock Based Compensation Expense





Stock based compensation expense was $39,300 in 2010 and $55,493 in 2009.  2010 stock based compensation consisted of shares issued to an officer, a new board member and a consultant, while 2009 stock based compensation expense consisted primarily of the amortization of the value of shares, originally issued to employees in 2006.  All shares were valued based on the stock price at the date of issuance.





Depreciation, depletion and accretion





Depreciation, depletion and accretion were $267,402 in 2010 and $272,178 in 2009.





Loss from Operations





Loss from operations was $1,560,523 and $2,325,026 in 2010 and 2009, respectively.   Loss from operations improved by $764,503 due primarily to the $1,903,686 asset impairment charge in 2009 compared to zero in 2010, the $237,584 decrease in operating expenses, offset by the $856,822 decrease in revenues in 2010 compared to 2009 and the $860,937 Colombian equity taxes recorded in 2010 compared to zero in 2009.




15





Interest Income, Net





Net interest income was $1,182 in 2010 compared to net interest income of $24,232 in 2009, due to lower cash balances and lower interest rates earned on money in banks in 2010 as compared to 2009.





Provision for Income Taxes





Provision for income taxes was zero in 2010 and 2009.





Net Loss





Net loss was $1,559,341 and $2,300,794 in 2010 and 2009, respectively.   The $741,453 improvement in net loss is due primarily to the improvement in loss from operations in 2010 compared to 2009.





Foreign Currency Translation Gain





Foreign currency translation gain was $182,959 in 2010 compared to a foreign currency translation gain of $230,328 in 2009.  The Colombian Peso to Dollar Exchange Rate averaged 1,911 and 2,060 in 2010 and 2009, respectively and was 1,803 and 1,937 at September 30, 2010 and September 30, 2009, respectively.


16





Comprehensive Loss





Comprehensive loss was $1,376,382 in 2010 compared to a comprehensive loss of $2,070,466 in 2009.  Comprehensive loss improved by $694,084 due primarily to the $764,503 improvement in loss from operations in 2010 compared 2009.





Liquidity and Capital Resources





We had a working capital deficit of $202,088 compared to working capital of $1,095,699 at December 31, 2009.  Working capital at September 30, 2010 consisted primarily of $883,752 of cash and cash equivalents and $59,292 of prepaid expenses, offset by $964,074 of accrued expenses and $190,374 of accounts payable.  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.





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 by operating activities totaled $241,602 in 2010 compared to net cash provided by operating activities of $521,807 in 2009.  The major components of the net cash used by operating activities in 2010 were the net loss of $1,559,341, offset by the $885,103 increase in accounts payable and accrued expenses and $267,402 provision for depletion, depreciation and amortization.  The major components of the net cash provided by operating activities in 2009 were the $1,903,686 asset impairment charge relating to our Rosablanca well, $447,347 increase in accounts payable and accrued expenses and $272,178 provision for depletion, depreciation and amortization, offset by the net loss of $2,300,794.





Net cash provided by investing activities totaled $31,500 in 2010 compared to net cash used by investing activities of $342,537 in 2009.  Net cash provided by investing activities in 2010 consisted primarily of $154,289 received from Pacific as reimbursement for previously capitalized pipeline expenditures, offset by $120,051 investment in oil and gas properties.  Net cash used in investing activities in 2009 consisted primarily of $1,713,949 investments in oil and gas properties and $400,408 investment in Colombian trust accounts, offset by $912,164 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 by financing activities totaled $2,983 and $2,348 in 2010 and 2009, respectively and consisted entirely of payments made on the Promissory Note.




17





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





We have no material exposure to interest rate changes.  We are subject to changes in the price of oil and exchange rates of the Colombian Peso, which are out of our control.  In our Osage property in Oklahoma, we sold oil at prices ranging from $71.41 to $72.57 and $68.61 to $77.15 per barrel in the three and nine months ended September 30, 2010, respectively, compared to $59.41 to $65.84 and $32.35 to $65.84 in the three and nine months ended September 30, 2009, respectively.  In our Cimarrona property in Colombia, we sold oil at prices ranging from $70.62 to $77.11 and $63.32 to $78.70 per barrel in the three and nine months ended September 30, 2010, respectively, compared to $57.33 to $68.39 and $30.90 to $68.39 in the three and nine months ended September 30, 2009, respectively.  The Colombian Peso to Dollar Exchange Rate averaged 1,833 and 2,016 in the three months ended June 30, 2010 and September 30, 2009, respectively and was 1,803 and 1,937 at September 30, 2009 and September 30, 2008, respectively.  The exchange rate averaged 1,911 and 2,060 for the nine months ended September 30, 2010 and September 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 (“ASC 932”).  Under this method, we initially capitalize expenditures for oil and gas property acquisitions until they are either determined to be successful (capable of commercial production) or unsuccessful.  The carrying value of all undeveloped oil and gas properties is evaluated periodically and reduced if such carrying value appears to have been impaired.  Leasehold costs relating to successful oil and gas properties remain capitalized while leasehold costs which have been proven unsuccessful are charged to operations in the period the leasehold costs are proven unsuccessful.  Costs of carrying and retaining unproved properties are expensed as incurred.





The costs of drilling and equipping development wells are capitalized, whether the wells are successful or unsuccessful.  The costs of drilling and equipping exploratory wells are capitalized until they are determined to be either successful or unsuccessful.  If the wells are successful, the costs of the wells remain capitalized.  If, however, the wells are unsuccessful, the capitalized costs of drilling the wells, net of any salvage value, are charged to operations in the period the wells are determined to be unsuccessful.  In 2009, we recorded an impairment charge of $1,903,686 relating to our well in the Rosablanca concession as we found no producible hydrocarbons.





18





The provision for depreciation and depletion of oil and gas properties is computed on the unit-of-production method. Under this method, we compute the provision by multiplying the total unamortized costs of oil and gas properties including future development, site restoration, and dismantlement abandonment costs, but excluding costs of unproved properties by an overall rate determined by dividing the physical units of oil and gas produced during the period by the total estimated units of proved oil and gas reserves. This calculation is done on a country-by-country basis.  As of September 30, 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 (“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.





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.





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Item 4.                      Controls and Procedures





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





Management conducted an assessment of the effectiveness of the Company’s internal control over financial reporting as of September 30, 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 September 30, 2010 is not effective.  Based on this assessment, management has determined that, as of September 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  September 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)
During the three months ended September 30, 2010, the following shares were issued:





In July 2010, we issued 90,000 shares of our Common Stock to a consultant.  In September 2010, we issued 500,000 shares of our Common Stock to a new director and 1,000,000 shares of our Common Stock to an officer.  All of the shares were valued at 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





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:  November 8, 2010
By:
/s/ Kim BradfordKim BradfordPresident and Chief Executive Officer





Date:  November 8, 2010
By:
/s/ Kim BradfordKim 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.

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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