OEDVQ Osage Exploration and Development Inc (CE)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2012 and 2011 (unaudited)

1. ORGANIZATION AND BASIS OF PRESENTATION

Osage Exploration and Development, Inc. (“Osage” or the “Company”) is an independent energy company engaged primarily in the acquisition, development, production and sale of oil, gas and natural gas liquids. The Company’s production activities are located in the State of Oklahoma and the country of Colombia. The principal executive offices of the Company are at 2445 Fifth Avenue, Suite 310, San Diego, CA 92101. Osage was organized on September 9, 2004 as Osage Energy Company, LLC, (“Osage LLC”) an Oklahoma limited liability company. On April 24, 2006 we merged with a non-reporting, Nevada corporation trading on the pink sheets, Kachina Gold Corporation, which was the entity which survived the merger, through the issuance of 10,000,000 shares of our common stock. The merger was accounted for as a recapitalization of Osage LLC rather than as a business combination.

The Nevada non-reporting corporation was incorporated under the laws of Canada on February 24, 2003 as First Mediterranean Gold Resources, Inc. (“FMGR”). The domicile of FMGR was changed to the State of Nevada on May 11, 2004. On May 24, 2004, the name of FMGR was changed to Advantage Opportunity Corp (“AOC”). On March 4, 2005, AOC changed its name to Kachina Gold Corporation (“KGC”). On April 24, 2006 KGC merged with Osage LLC, and on May 15, 2006, changed its name to Osage Energy Corporation, Inc. On July 2, 2007, Osage Energy Corporation, Inc. changed its name to Osage Exploration and Development, Inc. and changed its domicile to the State of Delaware. On February 27, 2008, the Company’s common stock began trading on the Over-the-Counter Bulletin Board under the symbol “OEDV”.

Osage prepared the accompanying unaudited consolidated financial statements in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) 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 2011 Form 10-K filed with the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with U.S. GAAP 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 to be expected for the entire year.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Going Concern

While the Company had net income in the nine months ended September 30, 2012, we have accumulated deficits of $7,464,562 (unaudited) at September 30, 2012 and $7,558,080 at December 31, 2011. Substantial portions of the losses are attributable to asset impairment charges, stock-based compensation, professional fees and interest expense. The Company’s operating plans require additional funds which may take the form of debt or equity financings. There is no assurance additional funds will be available. The Company’s ability to continue as a going concern is in substantial doubt and is dependent upon achieving profitable operations and obtaining additional financing.

Management of the Company has undertaken steps as part of a plan to improve operations with the goal of sustaining our operations for the next 12 months and beyond. These steps include (a) assigning a portion of our oil and gas leases in Logan County, Oklahoma (b) participating in drilling of wells in Logan County, Oklahoma within the next 12 months, (c) controlling overhead and expenses and (d) raising additional equity and/or debt. There is no assurance the Company can accomplish these steps and it is uncertain the Company will achieve profitable operations and obtain additional financing. There is no assurance additional financings will be available to the Company on satisfactory terms and conditions, if at all. If 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 unaudited consolidated financial statements.

On April 17, 2012, we issued a secured promissory note to Boothbay Royalty Co. for gross proceeds of $2,500,000. On April 27, 2012, we entered into a $10,000,000 senior secured note purchase agreement with Apollo Investment Corporation (see Note 5 - Debt).

Basis of Consolidation

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

Use of Estimates

The accompanying Interim Financial Statements have been prepared in accordance with U.S. GAAP. The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Osage’s consolidated financial statements are based on a number of significant estimates, including oil and gas reserve quantities which are the basis for the calculation of depreciation, depletion and impairment of oil and gas properties, as well as the cost and timing of its asset retirement obligations.

Cash and Equivalents

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

Concentration of Credit Risk

Financial instruments which potentially subject the Company to concentration of credit risk consist of cash and accounts receivable. Cash balances exceeded FDIC insurance protection levels by $255,000 at September 30, 2012 subjecting the Company to risk related to the uninsured balance. The deposits are held at large established bank institutions. The Company believes the risk of loss associated with these uninsured balances is remote. Accounts receivable are recorded at invoiced amount and generally do not bear interest. Any allowance for doubtful accounts is based on management’s estimate of the amount of probable losses due to the inability to collect from customers and working interest owners. Sales to three customers comprised approximately 99.3% and 98.7% of Osage’s total revenues for the three and nine months ended September 30, 2012, respectively, and sales to two customers comprised approximately 98.8% of Osage’s total revenues for the three and nine months ended September 30, 2011. Osage believes that, in the event its primary customers were unable or unwilling to continue to purchase Osage’s production, there are alternative buyers for its production at comparable prices.

Restricted Cash

In connection with the Boothbay Secured Promissory Note (see Note 5) the Company is required to deposit certain royalty interests of Boothbay’s into joint accounts held by the Company for the benefit of Boothbay.

Accounts Receivable and Allowance for Doubtful Accounts

The Company recognizes accounts receivable when sales are invoiced and regularly reviews accounts receivable for doubtful accounts. There was no allowance for doubtful accounts at September 30, 2012 or December 31, 2011.

Deferred Financing Costs

The Company incurred deferred financing costs in connection with the Note Purchase Agreement (see Note 5), which represented the fair value of warrants, placement fees and legal fees. Deferred financing costs of $3,268,334 are being amortized over the term of the Note Purchase Agreement on a straight-line basis.

During the nine months ended September 30, 2012, the Company made payments of $270,692 for deferred financing fees in connection with the Note Purchase Agreement and $100,000 was included in accrued expenses at September 30, 2012.

Deferred financing costs at September 30, 2012 were $2,807,825. Amortization of deferred financing costs was $272,607 and $460,509 for the three and nine months ended September 30, 2012, respectively. There were no deferred financing fees incurred during the three and nine months ended September 30, 2011.

Fair Value of Financial Instruments

As of September 30, 2012 and December 31, 2011, the fair value of cash, accounts receivable and accounts payable approximate carrying values because of the short-term maturity of these instruments.

Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 820, “Fair Value Measurements and Disclosures,” requires disclosure of the fair value of financial instruments held by the Company. ASC Topic 825, “Financial Instruments,” defines fair value, and establishes a three-level valuation hierarchy for disclosures of fair value measurement that enhances disclosure requirements for fair value measures. The carrying amounts reported in the consolidated balance sheets for receivables and current liabilities each qualify as financial instruments and are a reasonable estimate of their fair value because of the short period of time between the origination of such instruments and their expected realization and their current market rate of interest.

The three levels of valuation hierarchy are defined as follows:

The Company analyzes all financial instruments with features of both liabilities and equity under ASC Topic 480, “Distinguishing Liabilities from Equity,” and ASC Topic 815, “Derivatives and Hedging.”

As of September 30, 2012 and December 31, 2011 (audited), the Company did not identify any assets and liabilities that are required to be presented on the balance sheet at fair value.

Oil and Gas Properties

The Company follows the “successful efforts” method of accounting for our oil and gas exploration and development activities, as set forth in FASB ASC Topic 932 (“ASC 932”). Under this method, the Company initially capitalizes 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 related to oil and gas properties which have been proven unsuccessful are charged to operations in the period in which the properties 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 expensed in the period in which the wells are determined to be unsuccessful.

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 exclude 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, 2012 and December 31, 2011, our oil production operations were conducted in Colombia and in the United States (U.S.). 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. The Company will begin to amortize these costs when proved reserves are established or impairment is determined. During the nine months ended September 30, 2012 and 2011, the Company did not record impairment charges related to its oil and gas properties.

Other Property and Equipment

Non-oil and gas producing property and equipment are stated at cost and consist primarily of furniture, office equipment and vehicles used in our operations. Depreciation for non-oil and gas properties is recorded on the straight-line method at rates based on estimated useful lives ranging from three to five years. Maintenance and repairs, which do not improve or extend the lives of the respective assets, are expensed as incurred.

Impairment of Long-Lived Assets

The Company follows the guidance provided under FASB ASC Topic 360 (“ASC 360”), “Accounting for the Impairment or Disposal of Long-Lived Assets”, which addresses financial accounting and reporting for the impairment or disposal of long-lived assets. The Company periodically evaluates the carrying value of long-lived assets to be held and used in accordance with ASC 360. ASC 360 requires impairment losses to be recorded on long-lived assets used in operations when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying amounts. In that event, a loss is recognized based on the amount by which the carrying amount exceeds the fair market value of the long-lived assets. Loss on long-lived assets to be disposed of is determined in a similar manner, except that fair market values are reduced for the cost of disposal. During the nine months ended September 30, 2012 and 2011, the Company did not record impairment charges related to its long-lived assets.

Asset Retirement Obligations

In accordance with FASB ASC Topic 410 (“ASC 410”), “Accounting for Asset Retirement Obligations,” the Company records a liability for any legal retirement obligations on our oil and gas properties. The asset retirement obligations (“AROs”) 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 AROs by calculating the present value of estimated cash flows related to the liability. The AROs 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 AROs. 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.

Revenue Recognition

The Company recognizes sales from its properties using the sales method. Under the sales method, the working interest owners recognize sales of oil and gas regardless of the amount produced for the period. The sales method assumes any production sold by a working interest owner comes from that party’s share of the total reserves in place. Thus, whatever quantity is sold in any given period is the revenue for that party. No receivables, payables or unearned revenue are recorded.

Stock Based Compensation

The Company accounts for its stock-based compensation in accordance with FASB ASC Topic 718, “Share-Based Payment.” The Company recognizes in the statement of operations the grant-date fair value of stock options and other equity-based compensation issued to employees and non-employees. For stock-based awards the value is based on the market value for the stock on the date of grant and if the stock has restrictions as to transferability a discount is provided for lack of tradability. Stock option awards are valued using the Black-Scholes option-pricing model. For shares issued for services or property, the value is based on the market value for the stock on the date of grant.

During the three months ended September 30, 2012, we did not issue any stock or warrants to consultants for services rendered. During the nine months ended September 30, 2012, we issued 210,000 shares and 400,000 warrants to purchase shares of the Company’s common stock to consultants for services rendered, all of which vested immediately.

Total stock-based compensation expense was $13,800 and $522,111 for the three and nine months ended September 30, 2012, respectively, and $150,000 and $250,000 for the three and nine months ended September 30, 2011, respectively.

Income Tax

The Company follows FASB ASC Topic 740 (“ASC 740”), “Accounting for Uncertainty in Income Taxes.” As a result of the implementation of ASC 740, the Company made a comprehensive review of its portfolio of tax positions in accordance with recognition standards established by ASC 740. The Company recognized no material adjustments to liabilities or stockholders equity as a result of this review. When tax returns are filed, it is likely 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 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% likely of being realized upon settlement with the applicable taxing authority. The portion of the benefits associated with tax positions taken that exceeds the amount measured as described above is reflected as a liability for unrecognized tax benefits in the accompanying balance sheets along with any associated interest and penalties that would be payable to the taxing authorities upon examination. Interest associated with unrecognized tax benefits are classified as interest expense and penalties are classified in selling, general and administrative expenses in the Consolidated Statement of Operations. The Company did not have a provision for income taxes for 2012 or 2011. Due to a history of operating losses, the Company records a full valuation allowance against its net deferred tax assets and therefore recorded no tax provision related to its U.S. operations for the three and nine months ended September 30, 2012 and 2011.

At December 31, 2011, the Company had Federal net operating loss carry forwards of approximately $3.0 million which expire at various dates through 2031 and State net operating loss carry forwards of approximately $2.2 million which expire at various dates through 2032.

Net Income/Loss Per Share

In accordance with FASB ASC Topic 260 “Earnings Per Share,” the Company’s basic net income/loss per share of common stock is calculated by dividing net income/loss by the weighted-average number of shares of common stock outstanding for the period. The diluted net income/loss per share of common stock is computed by dividing the net income/loss using the weighted-average number of common shares including potential dilutive common shares outstanding during the period. Potential common shares are excluded from the computation of diluted net loss per share if anti-dilutive. Potential common shares consisted of 3,071,843 and 1,125,000 warrants to purchase common stock at September 30, 2012 and 2011, respectively.

The following table shows the computation of basic and diluted net income (loss) per share for the three and nine months ended September 30, 2012 and 2011:

1,125,000 warrants to purchase common stock were excluded from the diluted weighted average shares outstanding in all periods presented as their effect would have been anti-dilutive.

Recent Accounting Pronouncements

In May 2011, the FASB issued Accounting Standard Update (“ASU”) No. 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards (“IFRS”) of Fair Value Measurement—Topic 820.” ASU No. 2011-04 is intended to provide a consistent definition of fair value and improve the comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with U.S. GAAP and IFRS. The amendments include those that clarify the FASB’s intent about the application of existing fair value measurement and disclosure requirements, as well as those that change a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements. The update was effective for annual periods beginning after December 15, 2011. The adoption did not have a material impact on the Company’s consolidated financial statements.

In September 2011, the FASB issued ASU No. 2011-05, “Comprehensive Income (Topic 220): Presentation of Comprehensive Income as amended by ASU No. 2011-12, Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05.” This ASU eliminates the option to present the components of other comprehensive income as part of the statement of changes in stockholders’ equity. Rather, it gives an entity the choice to present the components of net income and other comprehensive income in either a single continuous statement or two separate but consecutive statements. Companies will continue to present reclassification adjustments from other comprehensive income to net income on the face of the financial statements. The components of comprehensive income and timing of reclassification of an item to net income do not change with this update. ASU No. 2011-05 requires retrospective application and is effective for annual and interim periods beginning after December 15, 2011. The Company adopted this standard in the first quarter of 2012 by presenting the components of net income and other comprehensive income in a single continuous statement.

On July 27, 2012, the FASB issued ASU 2012-02, Intangibles-Goodwill and Other (Topic 350) - Testing Indefinite-Lived Intangible Assets for Impairment. The ASU provides entities with an option to first assess qualitative factors to determine whether events or circumstances indicate that it is more likely than not that the indefinite-lived intangible asset is impaired. If an entity concludes that it is more than 50% likely that an indefinite-lived intangible asset is not impaired, no further analysis is required. However, if an entity concludes otherwise, it would be required to determine the fair value of the indefinite-lived intangible asset to measure the amount of actual impairment, if any, as currently required under U.S. GAAP. The ASU is effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012. Early adoption is permitted. The adoption of this pronouncement will not have a material impact on the Company’s consolidated financial statements.

Other recently issued ASUs were assessed and determined to be either not applicable or are not expected to have a material impact on the Company’s consolidated financial statements.

On April 21, 2011, the Company entered into a participation agreement (“Participation Agreement”) with Slawson Exploration Company (“Slawson”) and U.S. Energy Development Corporation (“USE”, Slawson and USE, together, the “Parties”). Pursuant to the terms of the Participation Agreement, Slawson and USE acquired 45% and 30% respectively, of our 10,000 acre Nemaha Ridge prospect in Logan County, Oklahoma for $4,875,000. In addition, the Parties shall carry Osage for 7.5% of the cost of the first three horizontal Mississippian wells, which means that for the first three horizontal Mississippian wells, the Company will provide 17.5% of the total well costs. After the first three wells, the Company is responsible for 25% of the total well costs. Revenue from wells drilled pursuant to the Participation Agreement shall be allocated 45% to Slawson, 30% to USE and 25% to Osage. Slawson will be the operator of all wells in the Nemaha Ridge prospect. The Company continues to acquire additional acreage in the Nemaha Ridge prospect and will offer the additional acreage to the Parties, at its cost, subject to their acceptance. At September 30, 2012, the Company had 7,738 net acres (47,217 gross) leased in Logan County. In December 2011, the Company began drilling the Wolf 1-29H, its first well in Logan County and in January 2012, the Company began drilling the Krittenbrink 2-36H, its second well in Logan County. In March 2012, the Company began well production and recognized its first oil revenues from these properties. In May, the Company began drilling its third well in Logan County, the Davis Farms 5-2H and recognized its first oil revenues from this property in August 2012. In September, the Company began drilling its fourth and fifth wells in Logan County – the McPhail 2-18H and the Hopfer 1-17MH. As of September 30, 2012, the Company had also completed three salt water disposal wells.

In addition to accumulating leases in Logan County, in 2011, the Company began to acquire leases in Pawnee County, Oklahoma, targeting the Mississippian formation. In July 2011, the Company purchased from B&W Exploration, Inc. (“B&W”) the Pawnee County prospect for $8,500. In addition, B&W is also entitled to an overriding royalty interest on the leases acquired and a 12.5% carry on the first $200,000 of lease bonus paid in the form of an assignment of 12.5% of the leases acquired. As of September 30, 2012, the Company had 2,904 net acres (3,804 gross) leased in Pawnee County. As of September 30, 2012, none of these leases have been assigned to B&W.

In 2011, the Company began to acquire leases in Coal County, Oklahoma, targeting the Woodford Shale formation. At September 30, 2012, we had 4,253 net (9,509 gross) acres leased in Coal County.

At September 30, 2012, the Company had leased an aggregate of 14,895 net (60,530 gross) acres across three counties in Oklahoma.

4. SEGMENT AND GEOGRAPHICAL INFORMATION

The Company operates in two segments and has activities in two geographical regions. The Oil / Gas segment engages primarily in the acquisition, development, production and sale of oil, gas and natural gas liquids. The Pipeline segment engages primarily in the transport of oil.

The following tables set forth revenues, income and assets by segment for the periods presented:

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

5. DEBT

2012 Activity

Apollo - Note Purchase Agreement

On April 27, 2012, we entered into a $10,000,000 senior secured note purchase agreement (“Note Purchase Agreement” or “Notes”) with Apollo Investment Corporation (“Apollo”). The Notes, which mature on April 27, 2015, are secured by substantially all of the assets of the Company, including a mortgage on all our Oklahoma leases. The Notes bear interest of Libor plus 15.0% with a Libor floor of 2.0%, with interest payable monthly. In addition, Apollo received a warrant to purchase 1,496,843 shares of common stock, exercisable at $0.01 per share, with a Black-Scholes value of $2,483,952 and an expiration date of April 27, 2017. Variables used in the valuation include (1) discount rate of 0.82%, (2) expected life of 5 years, (3) expected volatility of 245.0% and (4) zero expected dividends. The minimum draw amount on the Note Purchase Agreement is $1,000,000. At closing, we did not draw down any funds. At September 30, 2012, the amount outstanding under the Note Purchase Agreement was $1,000,000.

At closing of the Note Purchase Agreement, we paid $100,000 of a minimum placement fee to CC Natural Resource Partners, LLC (“CCNRP”) and issued a warrant to purchase 250,000 shares of common stock, exercisable at $0.01 per share, with a Black-Scholes value of $413,690 and an expiration date of April 27, 2014. Variables used in the valuation include (1) discount rate of 0.26%, (2) expected life of 2 years, (3) expected volatility of 242.0% and (4) zero expected dividends. We will pay CCNRP an additional minimum placement fee of 4.0% of the amount drawn, once we have drawn $2,500,000 under the Note Purchase Agreement, which $100,000 is included in accrued expenses in our consolidated balance sheet. In addition, we paid $170,692 in legal fees, of which $100,000 were paid to Apollo.

The Company recorded deferred financing costs in the aggregate amount of $3,268,334 in connection with the Note Purchase Agreement, which represented the fair value of warrants issued to Apollo and CCNRP, minimum placement fees and legal fees, which are amortized on a straight-line basis over the term of the Notes as the Company did not draw funds at issuance.

On each anniversary of the closing date, the Company will pay an administrative fee of $50,000. The Company is obligated to pay a quarterly standby fee, which accrues at a rate of 3.0%, on the amount of undrawn funds equal to the difference between $5,000,000 and the aggregate principal amount of notes issued on or after the closing date. The Company is subject to certain precedents in connection with each draw, an upfront fee equal to 2.0% of the principal amount of each draw, and is required to maintain a deposit account equal to 3 months of interest payments.

The Company is subject to various affirmative, negative and financial covenants under the Note Purchase Agreement along with other restrictions and requirements, all as defined in the Note Purchase Agreement. Affirmative covenants include by October 31st of each year beginning in 2012, a reserve report prepared as of the immediately preceding September 30, concerning the Company’s domestic oil and gas properties prepared by approved petroleum engineers, and thereafter as of September 30th of each year. Financial covenants include a $75,000 limitation per quarter on general and administrative costs in excess of the revenues generated by Cimarrona, LLC and the following:

Use of proceeds is limited to those purposes specified in the Note Purchase Agreement. The Notes are subject to mandatory prepayment in the event of certain asset sales, insurance or condemnation proceeds, issuance of indebtedness, extraordinary receipts and tax refunds. All terms are as defined in the Note Purchase Agreement.

Boothbay - Secured Promissory Note

On April 17, 2012, we issued a secured promissory note (“Secured Promissory Note”) to Boothbay Royalty Co., (“Boothbay”) for gross proceeds of $2,500,000. The Secured Promissory Note matures April 17, 2014 and bears interest of 18%, payable monthly. In addition, Boothbay received 400,000 shares for which the relative fair value of $386,545 was recorded as debt discount, a 1.5% overriding royalty on our leases in section 29, township 17 North, range 3 and a 1.7143% overriding royalty on our leases in section 36, township 19 North, range 4 West in Logan County, Oklahoma. The closing price of the Company’s common stock on April 17, 2012 was $1.14. The Secured Promissory Note is secured by a first mortgage (with power of sale), security agreement and financing statement covering a 5% overriding royalty interest, proportionately reduced, in all of the Company’s leases in Logan County, Oklahoma.

In connection with the Note Purchase Agreement and the Secured Promissory Note, the Company recognized $489,485 and $829,741 of interest expense, of which $181,000 and $298,277 was cash interest expense, for the three and nine months ended September 30, 2012, respectively. Non-cash interest expense related to the Note Purchase Agreement and the Secured Promissory Note represented $308,486 and $531,464 for the three and nine months ended September 30, 2012, respectively.

2011 Activity

Hoffman Note

On April 5, 2011, we issued a secured promissory note (“Hoffman Note”) to Peter Hoffman, an individual investor for $200,000. The Hoffman Note matured August 5, 2011, had a loan fee and prepaid interest of 250,000 shares of common stock, valued at $35,000, and was secured by an assignment of the Company’s future oil and gas leases in Logan County, Oklahoma. The Company repaid the Hoffman Note in full on May 24, 2011. At the time of issuance of the Hoffman Note, Mr. Hoffman owned approximately 13.2% of the Company. The Hoffman Note was agreed upon through arms-length negotiations.

Blackrock Note

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

6. COMMITMENTS AND CONTINGENCIES

Environment

Osage, as owner and operator of oil and gas properties, is subject to various Federal, State, and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the owner of real property and the lessee under oil and gas leases for the cost of pollution clean-up resulting from operations, subject the owner/lessee to liability for pollution damages and impose restrictions on the injection of liquids into subsurface strata. Although 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 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, 2012, 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 2011, the Company entered into a 36 month lease for its corporate offices in San Diego. The lease, including parking, was initially for $3,488 per month for the first year, increasing to $3,599 and $3,715 in the second and third years, respectively. In addition, the Company is responsible for all operating expenses and utilities. The lease required the Company to increase its security deposit from $3,381 to $10,000, with $3,299 and $3,415 of the security deposit to be applied to months 13 and 25, respectively, of the lease. In February 2012, the Company entered into a 24 month lease for a vehicle to be utilized by its operations in Oklahoma. Lease payments are $680 per month. Outside of the San Diego office and Oklahoma vehicle lease, the Company’s Oklahoma office and all leased equipment are under month-to-month operating leases. Rental expense totaled $14,344 and $42,727, and $13,163 and $40,263 for the three and nine months ended September 30, 2012 and 2011, respectively.

Future minimum commitments under operating leases are as follows as of September 30, 2012:

Legal Proceedings

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

Division de Impuestos y Actuanas Nacionales (“DIAN”), the Colombian tax authorities, levies a tax based on the equity value of Cimarrona. The equity tax for prior years comprised both current equity taxes as well as taxes assessed by DIAN on Cimarrona’s operations in 2001 and 2003 prior to its ownership by us. In 2010, the Company was notified by DIAN that it owes $883,742 in equity taxes relating to 2001 and 2003 equity tax years. To compute the value the equity tax is assessed upon, Cimarrona subtracted the cost of its non-producing wells in 2001 and 2003. However, DIAN’s position is that as long as the field is productive, Cimarrona should not have subtracted the cost of the non-producing wells. In May 2011, we settled in full the 2001 equity liability with DIAN. In January 2012, we were informed by DIAN that we have lost our appeal on the 2003 tax issue and we increased the amount attributable to the 2003 tax year by $322,288 to correspond to the amount DIAN indicates we owe for the 2003 tax year. We are currently in negotiations with DIAN about repayment terms for the 2003 tax year. The Company recognized $32,878 and $35,483 in equity tax for the three months ended September 30, 2012 and 2011, respectively, and $98,481 and $405,935 for the nine months ended September 30, 2012 and 2011, respectively.

8. LIABILITY FOR 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 (“AROs”) 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 AROs. No income tax is applicable to the ARO as of September 30, 2012 and December 31, 2011, because the Company records a valuation allowance on deductible temporary differences due to the uncertainty of its realization. A reconciliation of the Company’s asset retirement obligations for the periods presented is as follows:

9. EQUITY

Common Stock

On January 27, 2012, the Company issued 90,000 shares of common stock at $41,400 or $0.46 per share, to a consultant as compensation for services to be rendered March through August 2012.

On April 16, 2012, the Company issued 20,000 shares of common stock at $23,000 or $1.15 per share, to a consultant as compensation for services rendered.

On April 17, 2012, in connection with the Secured Promissory Note, we issued to Boothbay 400,000 shares of common stock at $385,656, the relative fair value (see Note 5 – Debt).

On August 1, 2012, in connection with a three-year employment agreement, we agreed to issue 150,000 shares of common stock at future dates as specified in the agreement. We will issue 50,000 shares on each of the first, second, and third anniversaries of the execution of the agreement subject to other terms and conditions of the agreement.

On August 26, 2012, a consultant who had previously been issued a warrant to purchase common stock exercised the warrant and purchased 200,000 shares of common stock for $2,000. (see “Warrants” below)

Warrants

On April 16, 2012, we issued a warrant to purchase 200,000 shares of common stock, exercisable at $0.01 per share, with a Black-Scholes value of $229,056 and a term of 2 years, to a consultant as compensation for services rendered. Variables used in the valuation include (1) discount rate of 0.27%, (2) expected life of 2 years, (3) expected volatility of 244.0% and (4) zero expected dividends. On August 24, 2012, the consultant exercised the warrant and purchased the 200,000 shares of common stock for $2,000.

On April 20, 2012, we issued a warrant to purchase 200,000 shares of common stock, exercisable at $0.01 per share, with a Black-Scholes value of $219,055 and a term of 2 years, to a consultant as compensation for services rendered. Variables used in the valuation include (1) discount rate of 0.29%, (2) expected life of 2 years, (3) expected volatility of 243.0% and (4) zero expected dividends.

On April 27, 2012, in connection with the Note Purchase Agreement, we issued a warrant to the investor to purchase 1,496,843 shares of common stock, exercisable at $0.01 per share, with a Black-Scholes value of $2,483,952 and a term of 5 years. At closing of the Note Purchase Agreement, we issued a warrant to the placement agent to purchase 250,000 shares of common stock, $0.0001 par value, exercisable at $0.01 per share, with a Black-Scholes value of $413,690 and a term of 2 years (see Note 5 – Debt).

10. SUBSEQUENT EVENTS

Subsequent to September 30, 2012, we assigned our interest in certain leases in Osage County for net consideration of approximately $117,000.

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

This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 that include, among others, statements of: expectations, anticipations, beliefs, estimations, projections, and other similar matters that are not historical facts, including such matters as: future capital requirements, development and exploration expenditures (including the amount and nature thereof), drilling of wells, reserve estimates (including estimates of future net revenues associated with such reserves and the present value of such future net revenues), future production of oil and gas, repayment of debt, business strategies, and expansion and growth of business operations. These statements are based on certain assumptions and analyses made by our management in light of past experience and perception of: historical trends, current conditions, expected future developments, and other factors that our management believes are appropriate under the circumstances. We caution the reader that these forward-looking statements are subject to risks and uncertainties, including those associated with the financial environment, the regulatory environment, and trend projections, that could cause actual events or results to differ materially from those expressed or implied by the statements. Such risks and uncertainties include those risks and uncertainties identified below. Significant factors that could prevent us from achieving our stated goals include: declines in the market prices for oil and gas, adverse changes in the regulatory environment affecting us, the inherent risks involved in the evaluation of properties targeted for acquisition, our dependence on key personnel, the availability of capital resources at terms acceptable to us, the uncertainty of estimates of proved reserves and future net cash flows, the risk and related cost of replacing produced reserves, the high risk in exploratory drilling and competition. You should consider the cautionary statements contained or referred to in this report in connection with any subsequent written or oral forward-looking statements that may be issued. We undertake no obligation to release publicly any revisions to any forward-looking statement to reflect events or circumstances after the date hereof or to reflect the occurrence of unanticipated events.

On April 8, 2008, we entered into a membership interest purchase agreement (the “Purchase Agreement”) with Sunstone Corporation (“Sunstone”) pursuant to which we acquired from Sunstone 100% of the membership interests in Cimarrona Limited Liability Company, an Oklahoma limited liability company (“Cimarrona LLC”). Cimarrona LLC owns 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 21 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 35,000 barrels of oil per day. The Purchase Agreement was effective as of April 1, 2008. The Cimarrona property is subject to an Ecopetrol Association Contract (the “Association Contract”) whereby we pay Ecopetrol S.A. (“Ecopetrol”) royalties of 20% of the oil produced. The pipeline is not subject to the Association Contract. The royalty amount for the Cimarrona property is paid in oil. In addition to the royalty, according to the Association Contract, Ecopetrol may, for no consideration, become a 50% partner, once an audit of revenues and expenses indicate that the partners in the Association Contract have received a 200% reimbursement of all historical costs to develop and operate the Guaduas field. We believe Ecopetrol could become a 50% partner in 2013, which would effectively reduce our cash flows by 50%. In addition, in 2022, the Association Contract with Ecopetrol terminates, at which time we will have no economic interest remaining in this property. The property and the pipeline are both operated by Pacific, which owns 90.6% of the Guaduas field. Pipeline revenues generated from Cimarrona primarily relate to transportation costs charged to third party oil producers, including Pacific.

In 2010, we began to acquire oil and gas leases in Logan County, Oklahoma targeting the Mississippian formation. The Mississippian formation is located on the Anadarko Shelf in northern Oklahoma and south-central Kansas. The top of this expansive carbonate hydrocarbon system is encountered between 4,000 and 6,000 feet and lies stratigraphically between the Pennsylvanian-aged Morrow Sand and the Devonian-aged Woodford Shale formations. The Mississippian formation may reach 600 feet in gross thickness and the targeted porosity zone is between 50 and 300 feet thick. The formation’s geology is well understood as a result of the thousands of vertical wells drilled and produced there since the 1940s. Beginning in 2007, horizontal drilling and multi-stage hydraulic fracturing treatments have demonstrated the potential for extracting significant additional quantities of oil and natural gas from the formation. On April 21, 2011, we entered into a participation agreement (the “Participation Agreement”) with Slawson Exploration Company (“Slawson”) and U.S. Energy Development Corporation (“USE”).Pursuant to the terms of the Participation Agreement, Slawson and USE acquired 45% and 30% respectively, of our 10,000 acre Nemaha Ridge prospect in Logan County, Oklahoma for $4,875,000. In addition, Slawson and USE shall carry Osage for 7.5% of the cost of the first three horizontal Mississippian wells, such that for the first three horizontal Mississippian wells, the Company will provide 17.5% of the total well costs. After the first three wells, the Company is responsible for 25% of the total well costs. Revenue from wells drilled pursuant to the Participation Agreement shall be allocated 45% to Slawson, 30% to USE and 25% to Osage. Slawson will be the operator of all wells in the Nemaha Ridge prospect. We are acquiring additional acreage in the Nemaha Ridge prospect and will offer the additional acreage to Slawson and USE, at our cost, subject to their acceptance. The Participation Agreement states that Osage will deliver acreage in the Nemaha Ridge Prospect to the Parties at a net Revenue Interest (“NRI”) of 78% unless Osage acquires the acreage at an NRI lower than 78%, in which case, the acreage will be delivered at the NRI acquired by Osage. Where Osage acquires leases with an NRI in excess of 78%, it has provided its management and consultants an overriding royalty interest (“ORRI”) equal to the difference between the NRI and 78%. At September 30, 2012, the Company had 7,738 net acres (47,217 gross) leased in Logan County. In December 2011, the Company began drilling the Wolf 1-29H, its first well in Logan County and in January 2012, the Company began drilling the Krittenbrink 2-36H, its second well in Logan County. In March 2012, the Company began well production and recognized its first oil revenues from these properties. In May, the Company began drilling its third well in Logan County, the Davis Farms 5-2H and we recognized our first oil revenues from this property in August 2012. In September, the Company began drilling its fourth and fifth wells in Logan County – the McPhail 2-18H and the Hopfer 1-17MH. As of September 30, 2012, the Company had also completed three salt water disposal wells.

In 2011, the Company began to acquire leases in Pawnee County, Oklahoma, targeting the Mississippian formation. In July 2011, we purchased from B&W Exploration, Inc. (“B&W”) the Pawnee County prospect targeting the Mississippian, for $8,500. In addition, B&W is also entitled to an overriding royalty interest on the leases acquired and a 12.5% carry on the first $200,000 of lease bonus paid in the form of an assignment of 12.5% of the leases acquired. As of September 30, 2012, the Company had 2,904 net acres (3,804 gross) leased in Pawnee County. As of September 30, 2012, none of these leases have been assigned to B&W.

In 2011, we also began to acquire leases in Coal County, Oklahoma, targeting the Woodford Shale formation. The Woodford Shale formation is located mainly in southeastern Oklahoma in the Arkoma Basin. The Woodford shale lies directly under the Mississippian and started as a vertical play, but horizontal drilling techniques and multi-stage fracturing technology have been used in the Woodford in recent years with much success. At September 30, 2012, we had 4,253 net (60,530 gross) acres leased in Coal County.

At September 30, 2012, we had leased an aggregate of 14,895 net (60,530 gross) acres across three counties in Oklahoma as follows:

We had an accumulated deficit of $7,464,562 at September 30, 2012 and $7,558,080 at December 31, 2011. In 2011, we recognized a one-time gain of $3,109,646 from assignment of leases in Logan County, Oklahoma. Our operating plans require additional funds that may take the form of debt or equity financings. There can be no assurance that any additional funds will be available. Our 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.

We anticipate we will need to raise at least $10,000,000 to sustain operations over the next 12 months, with the majority of the capital being used to drill additional wells in Logan County, Oklahoma. At present, the revenues generated from the Cimarrona and Logan County properties are only sufficient to cover field operating expenses and a portion of our overhead. We have undertaken steps as part of a plan to improve operations with the goal of sustaining our operations for the next 12 months and beyond. These steps include (a) assigning a portion of our oil and gas leases in Logan County, Oklahoma (b) participating in drilling of wells in Logan County, Oklahoma within the next 12 months, (c) controlling overhead and expenses and (d) raising additional capital and/or obtaining financing. There is no assurance we will successfully accomplish these steps and it is uncertain we will achieve profitable operations and/or obtain additional financing. There can be no assurance 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.

On April 17, 2012, we issued a secured promissory note (“Secured Promissory Note”) to Boothbay Royalty Co.(Boothbay) for $2,500,000. On April 27, 2012, we entered into a $10,000,000 senior secured note purchase agreement (“Note Purchase Agreement”) with Apollo Investment Corporation (“Apollo”) (see Note 5 - Debt, in the accompanying unaudited consolidated financial statements). We anticipate that we will draw down the full $10,000,000 available to us under the Note Purchase Agreement during the next 12 months to support the drilling in Logan County, as well as the other counties in Oklahoma.

Results of Operations

Three Months ended September 30, 2012 compared to Three Months ended September 30, 2011

Our total revenues for the three months ended September 30, 2012 and 2011 comprised the following:

Oil Sales

Oil Sales were $1,262,050, an increase of $879,991, or 230.3%, for the three months ended September 30, 2012 compared to $382,059 for the three months ended September 30, 2011. Oil sales increased due to an increase in the number of barrels sold as well as price increases. In Colombia, we sold 6,000 barrels (“BBLs”) at an average price of $100.54 in the 2012 period, compared to 4,000 BBLs at an average price of $96.37 in the 2011 period. In the United States (U.S.), we sold 9,667 BBLs at an average price of $96.64 in the 2012 period compared to 161 BBLs at an average price of $82.73 in the 2011 period. We began well production in Logan County, Oklahoma, in the first quarter of 2012, which accounted for the majority of the increase in oil sales in the United States.

Pipeline Sales

The Guaduas pipeline connects with the ODC pipeline (the “ODC Pipeline”) to transport oil to the port of Covenas in Colombia. Pipeline sales were $508,505, an increase of $36,364, or 7.7% for the three months ended September 30, 2012 compared to $472,141 for the three months ended September 30, 2011, primarily due to an increase in the average price per barrel charged from $1.77 in 2011 to $2.01 in 2012. The number of barrels transported remained constant in both periods at 2.69 million BBLs (our share was approximately 253.000).

Natural Gas Sales

Natural gas sales were $84,572 for the three months ended September 30, 2012 compared to $0 for the three months ended September 30, 2011. All of our natural gas sales are from the well production in Logan County, Oklahoma.

Total revenues were $1,855,127, an increase of $1,000,927, or 117.2% for the three months ended September 30, 2012 compared to $854,200 for the three months ended September 30, 2011. Oil sales accounted for 68.0% and 44.7% of total revenues in the 2012 and 2011 periods, respectively.

Oil production, net of royalties, was 14,102 BBLs, an increase of 9,336 BBLs, or 195.9% for the three months ended September 30, 2012 compared to 4,766 BBLs for the three months ended September 30, 2011, due to production increases in the U.S. U.S. production accounted for 68.6% and 3.4% of total production for the three months ended September 30, 2012 and 2011, respectively.

Natural gas production was 50,153 Mcf for the three months ended September 30, 2012. Gas production began in the first quarter of 2012 in our Logan County properties, and there was no production of natural gas during the three months ended September 30, 2011.

Operating Costs

Our operating costs were $407,073 for the three months ended September 30, 2012 compared to $283,201 for the three months ended September 30, 2011, due primarily to an increase in operating costs in the U.S. as a result of having three wells in production at September 30, 2012 and an increase in operating costs in Colombia on our wells and pipeline. Operating costs as a percentage of total revenues reduced to 21.9% in the 2012 period from 33.2% in 2011 period, as the percentage increase in revenues was much greater than the percentage increase in operating costs as new wells came into production. Operating costs as a percentage of revenues also declined as a result of the increased percentage of U.S. production, to 68.6% in the 2012 period from 3.4% in the 2011 period as average production cost per barrel of oil equivalent (“Production Cost/BOE”) in the U.S. for the three months ended September 30, 2012 was $4.65 compared to the average cost in Colombia of $31.20. Our average total Production Cost/BOE for the three months ended September 30, 2012 was $11.44.

General and Administrative Expenses

General and administrative expenses were $447,649 for the three months ended September 30, 2012, a reduction of $121,614 or 21.4%, compared to $569,263 for the three months ended September 30, 2011. As a percent of total revenues, general and administrative expenses decreased to 24.1% in the 2012 period from 66.6% in the 2011 period. The decrease of $121,614 was primarily due to a decrease in stock based compensation of $136,200. The decrease in stock based compensation expense for the three months ended September 30, 2012 related to the issuance of more shares and warrants to consultants for services in the prior year period. All shares were immediately vested. Stock based compensation for the three months ended September 30, 2012 was $13,800, compared to $150,000 in the three months ended September 30, 2011.

Equity Tax

Equity tax was $32,878 for the three months ended September 30, 2012 and $35,483 for the three months ended September 30, 2011. Division de Impuestos y Actuanas Nacionales (“DIAN”), the Colombian tax authorities, levies a tax based on the equity value of Cimarrona.

Depreciation, depletion and accretion

Depreciation, depletion and accretion were $226,682 for the three months ended September 30, 2012 and $112,900 for the three months ended September 30, 2011, an increase of $113,782 or 100.8%. Our depletion expense will continue to increase to the extent we are successful in our well production in Oklahoma.

Operating Income / (Loss)

Operating income was $740,845 for the three months ended September 30, 2012 compared to an operating loss of $146,647 for the three months ended September 30, 2011. The improvement in operating income is as a result of revenue growth of 117.2% which exceeded operating expense growth of 11.3%.

Interest Expense

Interest expense was $490,407 for the three months ended September 30, 2012 compared to $551 for the three months ended September 30, 2011, an increase of $489,856. The increase in interest expense during the 2012 period was primarily due to deferred financing fees amortization, interest expense, standby fees and debt discount amortization in connection with the Note Purchase Agreement and Secured Promissory Note. In the three months ended September 30, 2012, cash interest expense amounted to $181,000. The remaining non-cash interest expense of $308,856 consisted primarily of deferred financing fees of $272,607 and debt discount amortization of $35,878.

Provision for Income Taxes

Provision for income taxes was zero for the three months ended September 30, 2012 and 2011. Due to a history of operating losses, the Company records a full valuation allowance against its net deferred tax assets and therefore recorded no tax provision related to its U.S. operations for the current period.

Net Income / (Loss)

Net income was $250,976 for the three months ended September 30, 2012 compared to net loss of $142,787 for the three months ended September 30, 2011. The $393,763 improvement was as a result of revenue growth which exceeded growth in operating costs and expenses, offset in part by increased interest expense due to new financing facilities.

Foreign Currency Translation Gain / (Loss)

Foreign currency translation loss was $2,515 for the three months ended September 30, 2012 compared to a foreign currency translation gain of $17,861 for the three months ended September 30, 2011. The Colombian Peso to Dollar Exchange Rate averaged 1,796 and 1,793 for the three month periods ended September 30, 2012 and 2011, respectively and was 1,808 and 1,777 at September 30, 2012 and December 31, 2011.

Comprehensive Income / (Loss)

Comprehensive income was $248,461 for the three months ended September 30, 2012 compared to comprehensive loss of $124,926 for the three months ended September 30, 2011. The $373,387 improvement was as a result of revenue growth which exceeded growth in operating costs and expenses, offset in part by increased interest expense due to new financing facilities and foreign currency translation losses.

Nine Months ended September 30, 2012 compared to Nine Months ended September 30, 2011

Our total revenues for the nine months ended September 30, 2012 and 2011 comprised the following:

Oil Sales

Oil Sales were $3,036,599, an increase of $1,641,407, or 117.6%, for the nine months ended September 30, 2012 compared to $1,395,192 for the nine months ended September 30, 2011. Oil sales increased due to an increase in the number of barrels sold as well as price increases. In Colombia, we sold 14,000 barrels (“BBLs”) at an average price of $107.50 in the 2012 period, compared to 14,000 BBLs at an average price of $100.96 in the 2011 period. In the United States (“US”), we sold 21,653 BBLs at an average price of $96.64 in the 2012 period compared to 470 BBLs at an average price of $87.92 in the 2011 period. In March 2012 we began well production in our first and second wells in Logan County, Oklahoma, which accounted for the majority of the increase in oil sales in the U.S.

Pipeline Sales

The Guaduas pipeline connects with the ODC pipeline (the “ODC Pipeline”) to transport oil to the port of Covenas in Colombia. Pipeline sales were $1,396,165, an increase of $332,963, or 31.3% for the nine months ended September 30, 2012 compared to $1,063,202 for the nine months ended September 30, 2011, due to an 18.3% increase in the number of barrels transported to approximately 7.39 million BBLs (our share was approximately 695,000 BBLs) in the 2012 period from 6.24 million BBLs (our share was approximately 587,000 BBLs) in the 2011 period as well as an increase in the average price per barrel charged from $1.75 in 2011 to $2.01 in 2012.

Natural Gas Sales

Natural gas sales were $137,698 for the nine months ended September 30, 2012 compared to $0 for the nine months ended September 30, 2011. We recognized our first natural gas sales during the second quarter of 2012.

Total revenues were $4,570,462, an increase of $2,112,068, or 85.9% for the nine months ended September 30, 2012 compared to $2,458,394 for the nine months ended September 30, 2012. Oil sales accounted for 66.5% and 56.8% of total revenues in the 2012 and 2011 periods, respectively.

Production, net of royalties, was 33,874 BBLs, an increase of 19,417 BBLs, or 134.3% for the nine months ended September 30, 2012 compared to 14,457 BBLs for the nine months ended September 30, 2011 due to production increases in the U.S. U.S. production accounted for 63.9% and 3.3% of total production for the nine months ended September 30, 2012 and 2011, respectively.

Operating Costs

Our operating costs were $1,134,932 for the nine months ended September 30, 2012 compared to $702,378 for the nine months ended September 30, 2011, due primarily to an increase in operating costs in Logan County, Oklahoma. Operating expenses as a percentage of total revenues declined to 24.8% in the 2012 period from 28.6% in 2011 period, as the percentage increase in revenues was greater than the percentage increase in operating costs as new wells came into production. Operating costs as a percentage of revenues also declined as a result of the increased percentage of U.S. production, to 63.9% in the 2012 period from 3.3% in the 2011 period as average Production Cost/BOE in the U.S. for the nine months ended September 30, 2012 was $5.10 compared to the average cost in Colombia of $35.24. Our average total Production Cost/BOE for the nine months ended September 30, 2012 was $15.12.

General and Administrative Expenses

General and administrative expenses were $1,849,268 for the nine months ended September 30, 2012, an increase of $410,625 or 28.5%, compared to $1,438,643 for the nine months ended September 30, 2011. As a percent of total revenues, general and administrative expenses decreased to 40.5% in the 2012 period from 58.5% in the 2011 period. The increase of $410,625 was primarily due to increases in stock based compensation of $272,111 and legal and professional fees of $64,015 related primarily to financing and geological services. The increase in stock based compensation expense of $272,111 for the nine months ended September 30, 2012 related to the issuance of shares and warrants to consultants for services. All shares were immediately vested. Stock based compensation for the nine months ended September 30, 2012 was $522,111 compared to $250,000 for the nine months ended September 30, 2011.

Equity Tax

Equity tax was $98,481 for the nine months ended September 30, 2012 and $405,935 for the nine months ended September 30, 2011. Division de Impuestos y Actuanas Nacionales (“DIAN”), the Colombian tax authorities, levies a tax based on the equity value of Cimarrona. The 2012 equity tax of $98,481 related to the current 2012 assessment, and the 2011 equity tax of $405,935 related to an additional 2003 assessment, which was prior to ownership by us.

Depreciation, depletion and accretion

Depreciation, depletion and accretion were $565,705 for the nine months ended September 30, 2012 and $322,607 for the nine months ended September 30, 2011, an increase of $243,098 or 75.4%. Our depletion expense will continue to increase to the extent we are successful in our well production in Oklahoma.

Operating Income / (Loss)

Operating income was $922,075 for the nine months ended September 30, 2012 compared to an operating loss $411,169 for the nine months ended September 30, 2011. The improvement in operating results of $1,333,244 was due to the increase in revenues of $2,112,068 for the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011, partially offset by the $778,824 increase in operating expenses during the same periods.

Interest Expense

Interest expense was $832,172 for the nine months ended September 30, 2012 compared to $136,653 for the nine months ended September 30, 2011, an increase of $695,520. The increase in interest expense during the 2012 period was primarily due to deferred financing fees amortization, interest expense, standby fees and debt discount amortization in connection with the Note Purchase Agreement and Secured Promissory Note. Interest expense for the 2011 period is for the Blackrock Promissory Note issued in January 2011 and repaid in May 2011, and the Hoffman Note issued in April 2011 and repaid in May 2011. In the nine months ended September 30, 2012, cash interest expense amounted to $298,277. The remaining non-cash interest expense of $533,896 consisted primarily of deferred financing fees of $460,509 and debt discount amortization of $70,955.

Gain from Assignment of Leases

During the nine months ended September 30, 2011 we recognized a gain from assignment of leases of $3,109,646. The gain related to the assignment of leases in the Nemaha Ridge prospect in Logan County, Oklahoma pursuant to the Participation Agreement. There was no similar gain during the nine months ended September 30, 2012.

Provision for Income Taxes

Provision for income taxes was zero for the nine months ended September 30, 2012 and 2011. Due to a history of operating losses, the Company records a full valuation allowance against its net deferred tax assets and therefore recorded no tax provision related to its U.S. operations for the current period.

Net Income

Net income was $93,518 for the nine months ended September 30, 2012 compared to net income of $2,567,904 for the nine months ended September 30, 2011. The decrease in net income of $2,474,386 is primarily due to the $3,109,646 gain from assignment of leases in 2011 which was not repeated in the 2012 period, an increase of $695,520 in interest expense and partially offset by the improvement in operating income of $1,333,244.

Foreign Currency Translation Gain/ (Loss)

Foreign currency translation loss was $10,014 for the nine months ended September 30, 2012 compared to a gain of $24,657 for the nine months ended September 30, 2011. The Colombian Peso to Dollar Exchange Rate averaged 1,793 and 1,823 for the nine month periods ended September 30, 2012 and 2011, respectively and was 1,808 and 1,934 at September 30, 2012 and September 30, 2011.

Comprehensive Income

Comprehensive income was $83,504 for the nine months ended September 30, 2012 compared to a comprehensive income of $2,592,561 for the nine months ended September 30, 2011. Comprehensive income decreased by $2,529,257 due to the $2,474,386 decrease in net income in the 2012 period compared to the 2011 period and the $34,671 decrease in foreign currency translation to a loss in the 2012 period compared to a gain in the 2011 period.

Liquidity and Capital Resources

Net cash provided by operating activities totaled $1,719,937 for the nine months ended September 30, 2012, compared to net cash used by operating activities of $199,521 for the nine months ended September 30, 2011. The major components of net cash provided by operating activities for the nine months ended September 30, 2012 included non-cash activities which consisted of warrants and shares issued for services of $448,111, provision for depreciation, depletion and amortization of $565,705, amortization of deferred financing costs of $460,509, shares issued for services of $74,000 and amortization of debt discount of $70,955. Other components included the $337,434 increase in accounts payable and accrued expenses due primarily to our Oklahoma operations related to well production and drilling and the $450,145 increase in our joint operating account for Cimarrona, and partially offset by an increase in accounts receivable of $606,821. Net cash used by operating activities for the nine months ended September 30, 2011 totaled $199,521, The major components of the net cash used by operating activities in 2011 were the $3,109,646 gain on assignment of leases and the $220,357 increase in accounts receivable, offset by $2,567,904 net income, the $322,607 provision for depreciation and depletion and the $250,000 value of shares issued for services.

Net cash used in investing activities totaled $5,678,438 for the nine months ended September 30, 2012 and consisted of investments in oil & gas wells, as well as additional lease purchases of $9,954,470 and partially offset by net proceeds from assignment of leases of $4,274,532. Net cash provided by investing activities in 2011 totaled $2,775,841 and consisted primarily of $4,758,980 net proceeds from assignment of leases, offset by $1,961,329 investments in oil and gas properties.

Net cash provided by financing activities totaled $3,231,308 for the nine months ended September 30, 2012 and consisted of $2,500,000 proceeds from the Secured Promissory Note, $1,000,000 proceeds from the Apollo Note, partially offset by $270,692 payment of deferred financing costs related to the Apollo Note Purchase Agreement. Net cash provided by financing activities totaled zero in 2011, consisting of $700,000 of proceeds from the Blackrock Note and the Hoffman Note, both of which were repaid in full in 2011.

Our capital expenditures are directly related to drilling operations and the completion of successful wells. Our level of expenditures in the U.S. is dependent upon successful operations and availability of financing.

Effect of Changes in Prices

Changes in prices during the past few years have been a significant factor in the oil and gas (“O&G”) industry. The price received for the oil produced by us fluctuated significantly during the last year. Changes in the price received for our O&G is set by market forces beyond our control as well as governmental intervention. The volatility and uncertainty in O&G prices have made it more difficult for a company like us to increase our O&G asset base and become a significant participant in the O&G industry. We currently sell all of our O&G production to Hocol in Colombia, Slawsonand Coffeyville in the U.S. However, in the event these customers discontinued O&G 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 Logan county properties, we sold oil and gas at prices ranging from $82.70 to $106.49 per barrel and $3.39 to $4.72 per MCF. In our Osage property, we sold oil at prices ranging from $79.79 to $100.95 per barrel during the nine months ended September 30, 2012 compared to $84.84 to $96.89 per barrel during the nine months ended September 30, 2011. In our Cimarrona property in Colombia, we sold oil at prices ranging from $94.45 to $116.13 per barrel during the nine months ended September 30, 2012 compared to $82.21 to $120.22 during the nine months ended September 30, 2011. The Colombian Peso to Dollar Exchange Rate averaged approximately 1796 and 1,793 during the three months ended September 30, 2012 and 2011, respectively and 1,793 and 1,823 during the nine months ended September 30, 2012 and 2011, respectively. The Colombian Peso to Dollar Exchange Rate was 1,808 and 1,935 at September 30, 2012 and 2011, respectively.

Oil and Gas Properties

We follow the “successful efforts” method of accounting for our O&G exploration and development activities, as set forth in FASB ASC Topic 932 (“ASC 932”). Under this method, we initially capitalize expenditures for O&G property acquisitions until they are either determined to be successful (capable of commercial production) or unsuccessful. The carrying value of all undeveloped O&G properties is evaluated periodically and reduced if such carrying value appears to have been impaired. Leasehold costs relating to successful O&G 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 expensed in the period the wells are determined to be unsuccessful. We did not record any impairment charges during the nine months ended September 30, 2012 or 2011. The provision for depreciation and depletion of O&G properties is computed on the unit-of-production method. Under this method, we compute the provision by multiplying the total unamortized costs of O&G 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 O&G produced during the period by the total estimated units of proved O&G reserves. This calculation is done on a country-by-country basis. As of September 30, 2012 and 2011, our oil production operations were conducted in Colombia and in the U.S. 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 O&G 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 FASB ASC Topic 410 (“ASC 410”), “Accounting for Asset Retirement Obligations,” we record a liability for any legal retirement obligations on our O&G 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:

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 its 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 (“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 officers, 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 (“ICFR”) as of September 30, 2012, 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 ICFR as of September 30, 2012 is not effective. Based on this assessment, management has determined that, as of September 30, 2012, there were material weaknesses in our ICFR. 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 U.S. GAAP; (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 ICFR. Management’s report was not subject to attestation by the Company’s independent registered public accounting firm pursuant to temporary rules of the SEC 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 ICFR during the three months ended September 30, 2012 that have materially affected, or are reasonably likely to materially affect, the Company’s ICFR.

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

On January 27, 2012, the Company issued 90,000 shares of common stock for$41,400, or $0.46 per share, to a consultant as compensation for services to be rendered March 2012 through August 2012.

On April 16, 2012, the Company issued 20,000 shares of common stock at $23,000, or $1.15 per share, to a consultant as compensation for services rendered.

On April 16, 2012, we issued a warrant to purchase 200,000 shares of common stock, exercisable at $0.01 per share, with a Black-Scholes value of $229,056 and a term of 2 years to a consultant as compensation for services rendered.

On April 17, 2012, in connection with the Secured Promissory Note, we issued to Boothbay 400,000 shares of common stock at $385,656, the relative fair value.

On April 20, 2012,we issued a warrant to purchase 200,000 shares of common stock, exercisable at $0.01 per share, with a Black-Scholes value of $219,055 and a term of 2 years to a consultant as compensation for services rendered.

On April 27, 2012, in connection with the Note Purchase Agreement, we issued a warrant to the investor to purchase 1,496,843 shares of common stock, exercisable at $0.01 per share, with a Black-Scholes value of $2,483,952 and a term of 5 years. At closing of the Note Purchase Agreement, we issued a warrant to the placement agent to purchase 250,000 shares of common stock, $0.0001 par value, exercisable at $0.01 per share, with a Black-Scholes value of $413,690 and a term of 2 years.

On August 26, 2012, a consultant who had previously been issued a warrant to purchase common stock exercised the warrant and purchased 200,000 shares of common stock for $2,000.

The issuance of the securities of the Company in the above transactions was deemed to be exempt from registration under the Securities Act of 1933 by virtue of Section 4(2) thereof or Rule 506 of Regulation D promulgated there under, as transactions by an issuer not involving a public offering. With respect to the transactions listed above, no general solicitation was made by either the Company or any person acting on the Company’s behalf; the securities sold are subject to transfer restrictions; and the certificates for the shares contain an appropriate legend stating that such securities have not been registered under the Securities Act of 1933 and may not be offered or sold absent registration or pursuant to an exemption there from.

Item 3. Default upon Senior Securities

None.

Item 4. Removed and Reserved

None.

Item 5. Other Information

(a) None.

(b) None.

Item 6. Exhibits

See Exhibit Index attached hereto.

  SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf of the undersigned thereunto duly authorized.