OEDVQ Osage Exploration and Development Inc (CE)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2014 and 2013 (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, natural gas and natural gas liquids. The Company’s production activities are located in the State of Oklahoma. The principal executive offices of the Company are at 2445 Fifth Avenue, Suite 310, San Diego, CA 92101.

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 2013 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

As a result of production delays outside of the Company’s control, the Company was not in compliance with certain covenants as of June 30, 2014 and March 31, 2014, including the minimum production covenant under the senior secured note purchase agreement (see Note 5 - Debt).

On April 27, 2012, we entered into a $10,000,000 senior secured note purchase agreement with Apollo Investment Corporation. On April 5, 2013 we amended this agreement, increasing the facility to $20,000,000 and on April 7, 2014 we further amended this agreement, increasing the facility to $30,000,000, extending the term of the facility by one year, reducing the interest rate from Libor plus 15% to Libor plus 11% and agreeing to modify the covenants to reflect the transition from participant to operator. The Company also drew down an additional $5,000,000. The Company and the lender are still in discussions about modifications to the covenants and the existing covenants, some of which the Company is not in compliance with, remain in place until new covenants are agreed upon.

In the six months ended June 30, 2014, the Company raised approximately $6.7 million of gross proceeds in a private placement. (See Note 10 - Equity)

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) becoming operators of our own wells, (b) participating in drilling of wells in Logan County, Oklahoma, (c) controlling overhead and expenses, and (d) raising additional equity and/or debt.

The Company’s operating plans require additional funds which may take the form of debt or equity financings. The Company’s ability to continue as a going concern is dependent upon achieving profitable operations and obtaining additional financing. There is no assurance additional funds will be available on acceptable terms or at all. This raises substantial doubt about the Company’s ability to continue as a going concern.

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.

Basis of Consolidation

The consolidated financial statements include the accounts of Osage and its wholly owned subsidiaries, Osage Energy Company, LLC and Osage Exploration and Development Operating, 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. The results, assets and liabilities of the Company’s former wholly owned subsidiary, Cimarrona, LLC, have been presented as discontinued operations in the consolidated financial statements.

Use of Estimates

The preparation of financial statements in conformity with US 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 materially from those estimates. Management used significant estimates in determining the carrying value of its oil and gas producing assets and the associated depreciation and depletion expense related to sales volumes. The significant estimates include the use of proved oil and gas reserve estimates and the related present value of estimated future net revenues therefrom.

Reclassifications

Certain amounts included in the prior year financial statements have been reclassified to conform to the current year’s presentation. These reclassifications have no affect on the reported results in 2014 or 2013.

Risk Factors Related to Concentration of Sales and Products

The Company’s future financial condition and results of operations depend upon prices received for its oil and natural gas and the costs of finding, acquiring, developing and producing reserves. Prices for oil and natural gas are subject to fluctuations in response to changes in supply, market uncertainty and a variety of other factors beyond the Company’s control. These factors include worldwide political instability (especially in the Middle East), the foreign supply of oil and natural gas, the price of foreign imports, the level of consumer product demand and the price and availability of alternative fuels.

Cash and Equivalents

Cash and equivalents consist of short-term, highly liquid investments readily convertible into cash with an original maturity of three months or less.

Concentration of Credit Risk

Financial instruments that potentially subject the Company to concentrations of credit risk are cash and accounts receivable arising from its normal business activities. The Company places its cash in what it believes are credit-worthy financial institutions. However, the Company’s cash balances have exceeded the FDIC insured levels at various times during the three and six months ended June 30, 2014 and 2013. The Company maintains cash accounts only at large, high quality financial institutions and believes the credit risk associated with cash held in banks exceeding the FDIC insured levels is remote. The Company generated substantially all of its revenues from six customers in the three and six months ended June 30, 2014 and four customers in prior year comparable quarter.

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 $3,959,448 are being amortized over the term of the Note Purchase Agreement on a straight-line basis, which approximates the effective interest method.

Deferred financing costs net of accumulated amortization at June 30, 2014 were $1,390,642. Amortization of deferred financing costs was $190,499 and $538,482 for the three and six months ended June 30, 2014, respectively and $326,962 and $641,424 for the three and six months ended June 30, 2013, respectively.

Restricted Cash

In connection with the Apollo Note Purchase Agreement, as amended (see Note 5), the Company has classified $812,500 and $850,000, representing three months interest, as restricted cash as of June 30, 2014 and December 31, 2013, respectively. The Company has also pledged $58,465 for certain bonds and sureties at June 30, 2014. Restricted cash at June 30, 2014 was $870,965, compared to $908,645 at December 31, 2013.

Risk Management Activities

The Company has entered into certain derivative financial instruments to manage the inherent uncertainty of future revenues. The Company does not intend to hold or issue derivative financial instruments for speculative purposes and has elected not to designate any of its derivative instruments for hedge accounting treatment. These derivative financial instruments are marked to market at each reporting period.

Net Income/Loss Per Share

In accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“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.

The following table shows the computation of basic and diluted net income (loss) per share for the three and six months ended June 30, 2014 and 2013:

Potential common shares consisted of 7,287,559 and 1,696,843 warrants and options to purchase common stock at June 30, 2014 and 2013, respectively. All of these warrants and options were excluded from the computations for the three and six months June 30, 2014 and 2013, as their effect would have been anti-dilutive.

Fair Value of Financial Instruments

As of June 30, 2014 and December 31, 2013, the fair value of cash and equivalents, accounts receivable, notes payable, accounts payable and accrued expenses approximate carrying values because of the short-term maturity of these instruments.

FASB ACS 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 June 30, 2014 the Company identified certain derivative financial instruments which required disclosure at fair value on the balance sheet.

The following table presents information for those assets and liabilities requiring disclosure at fair value as of 2014:

The following methods and assumptions were used to estimate the fair values in the tables above.

Level 2 Fair Value Measurements

Commodity derivatives — The fair values of commodity derivatives are estimated using internal option pricing models based upon forward curves and data obtained from independent third parties for contracts with similar terms or data obtained from counterparties to the agreements.

Recent Accounting Pronouncements

The Company does not expect the adoption of any recently issued accounting pronouncements to have a material effect on the consolidated financial statements.

Depreciation and depletion expense for oil and gas properties totaled $1,334,307 and $2,327,259 in the three and six months ended June 30, 2014 and 2013, respectively and $213,128 and $478,733 in the three and six months ended June 30, 2013, respectively.

On December 12, 2013, Osage and Slawson entered into an agreement (the “Partition Agreement”) which amended the Participation Agreement related to certain lands located within the Nemaha Ridge in Logan County, Oklahoma, and for the exploration and development of those leases by the parties.

Under the Partition Agreement and effective as of September 1, 2013, Slawson agreed to assign all of its rights, title and interest in and to the oil and gas leases and force-pooled acreage which are part of the Nemaha Ridge Project within certain sections to Osage and Osage agreed to assign all of its rights, title and interest in and to the oil and gas leases and force-pooled acreage which are part of the Nemaha Ridge Project within certain sections to Slawson, such that the net acreage controlled by the parties would remain substantially unchanged, but that the acreage controlled by each of the parties in undeveloped sections would be located in sections where the other party did not control acreage. The parties also agreed that the Participation Agreement would terminate as to all lands within the Nemaha Ridge Project except for lands within sections already developed by the parties which shall continue to be controlled by the Participation Agreement.

As a result of the Partition Agreement, Osage has become the project operator on much of its acreage in the Nemaha Ridge Project. As of June 30, 2014, Osage operated or has the right to operate approximately 4,183 net acres (6,301 gross), and remains joint-venture or potential joint-venture partners with others in approximately 5,185 net acres (30,088 gross).

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. Subsequently, B&W shall have an option to purchase a 12.5% share of leasehold acquired on a heads-up basis. As of June 30, 2014, the Company had 4,190 net acres (5,085 gross) leased in Pawnee County. As of June 30, 2014, none of these leases have been assigned to B&W.

In 2011, we also began to acquire leases in Coal County, Oklahoma, targeting the Oily Woodford Shale formation. The Oily Woodford Shale formation is located mainly in southeastern Oklahoma in the Arkoma Basin. The Oily 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 June 30, 2014, we had 4,246 net (9,509 gross) acres leased in Coal County.

At June 30, 2014 we have leased 17,804 net (50,983 gross) acres across three counties in Oklahoma as follows:

4. SEGMENT AND GEOGRAPHICAL INFORMATION

At June 30, 2014, the Company’s continuing operations comprised one segment in one geographic region.

5. DEBT

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 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. In addition, we paid $170,692 in legal fees, of which $100,000 were paid to Apollo. In December 2012, we paid an additional $380,000 in placement fees. We also issued a warrant to purchase 100,000 shares of common stock, exercisable at $0.01 per share, with a Black-Scholes value of $89,952 and a term of five years, to the placement agent for the Note Purchase Agreement and amended the term of the warrant granted on April 27, 2012 from two to five years, with a Black-Scholes value of $1,161. Variables used in the valuation include (1) discount rate of 0.72%, (2) expected life of five years, (3) expected volatility of 242.0% and (4) zero expected dividends. In December 2013 we paid an additional $100,000 in placement fees and in April 2014 we paid $100,000 in additional placement fees.

On April 5, 2013 the Company and Apollo amended the Note Purchase Agreement, increasing the amount of the facility to $20,000,000 and modifying certain covenants for the remainder of the Note Purchase Agreement term. The Company paid an amendment fee of $100,000 which is being amortized over the remaining term of the Note Purchase Agreement.

On August 12, 2013, the Company and Apollo amended the Note Purchase Agreement. The amendment required that the Company, within 75 days of the effective date as defined in the amendment, complete either (1) a sale of certain assets, or (2) the issuance of capital stock in a transaction that resulted in aggregate net proceeds as defined in the amendment. In the event that the Company did not complete either one of the aforementioned transactions, the Company would have been required under the terms of the amendment to issue to Apollo additional warrants equivalent to three percent of the Company’s common stock, on a fully-diluted basis. On October 7, 2013, the Company completed the sale of its membership interests in Cimarrona LLC as more fully discussed in Note 11. This sale satisfied the requirements of the amendment and the Company is thus not obligated to issue additional Warrants to Apollo.

During the quarter ended June 30, 2014, we drew down $5,000,000 in additional funds and, as of June 30, 2014, the amount outstanding under the Note Purchase Agreement was $25,000,000. On April 3, 2014, the Company and Apollo amended the Note Purchase Agreement, increasing the amount of the total facility to $30,000,000, extending the term by one year and reducing the interest rate from Libor plus 15% to Libor plus 11%. The parties also agreed to modify future covenants to reflect the Company’s transition from participant to operator.

The Company has recorded deferred financing costs in the aggregate amount of $3,959,448 in connection with the Note Purchase Agreement, which represented the fair value of warrants issued to Apollo and CCNRP, placement fees, amendment fees and legal fees, which are amortized on a straight-line basis over the term of the Notes, which approximates the effective interest method, as the Company did not draw funds at issuance.

On each anniversary of the closing date, the Company is obligated to pay an administrative fee of $50,000. 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 three months of interest payments.

The Company is subject to various affirmative, negative and financial covenants under the Note Purchase Agreement as amended 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.

The Company and Apollo are negotiating new covenants to the Note Purchase Agreement. Until these negotiations are complete existing covenants, some of which the Company is not in compliance with, remain in place. Accordingly, the Company has classified borrowings under the Note Purchase Agreement as short term in the accompanying consolidated balance sheets.

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 had a maturity date of April 17, 2014 and bore interest of 18%, payable monthly. In addition, Boothbay received 400,000 shares of common stock 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 was 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. The Company repaid the Secured Promissory Note in full in December 2013.

In connection with the Note Purchase Agreement, the Company recognized $1,215,360 of interest expense, of which $190,499 was non-cash interest expense and $1,024,861 was cash interest expense, for the three months ended June 30, 2014. For the six months ended June 30, 2014, the Company recognized $2,425,920 of interest expense related to this facility, of which $538,482 was non-cash interest expense and $1,887,438 was cash interest expense. In connection with the Note Purchase Agreement and the Secured Promissory Note, the Company recognized $1,129,640 of interest expense, of which $375,112 was non-cash interest expense and $754,528 was cash interest expense, for the three months ended June 30, 2013. For the six months ended June 30, 2013, the Company recognized $1,896,116 of interest expense related to these facilities, of which $732,839 was non-cash interest expense and $1,163,306 was cash interest expense.

6. DERIVATIVE FINANCIAL INSTRUMENTS

The Company entered into certain derivative financial instruments with respect to a portion of its oil and gas production in the third quarter of 2013. Prior thereto, the Company had not entered into any derivative financial instruments. These instruments are used to manage the inherent uncertainty of future revenues due to commodity price volatility and currently include only costless price collars. The Company does not intend to hold or issue derivative financial instruments for speculative trading purposes and has elected not to designate any of its derivative instruments for hedge accounting treatment.

As of June, 2014, the Company had the following open oil derivative positions. These oil derivatives settle against the average of the daily settlement prices for the WTI first traded contract month on the New York Mercantile Exchange (“NYMEX”) for each successive day of the calculation period.

As of June 30, 2014, the Company had the following open natural gas derivative positions. These natural gas derivatives settle against the NYMEX Penultimate for the calculation period.

Cash settlements and unrealized gains and losses on fair value changes associated with the Company’s commodity derivatives are presented in the “Oil and gas derivatives’ caption in the accompanying consolidated statements of earnings.

The following table sets forth the cash settlements and unrealized gains and losses on fair value changes for commodity derivatives for the three and six months ended June 30, 2014 and 2013.

On October 15, 2013, the Company entered into an Intercreditor Agreement with Apollo and BP Energy Company to provide collateral for its oil and gas derivative financial instruments. BP Energy Corporation North America simultaneously provided a Guarantee for $25 million as collateral for its obligations to the Company.

7. 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 June 30, 2014, 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.

Operating Leases

In February 2011, the Company entered into a 36 month lease for its corporate offices in San Diego. In February 2014, the Company amended this lease to extend the term for an additional three years through February 2017. In February 2012, the Company entered into a 24 month lease for a vehicle to be utilized by its operations in Oklahoma and entered into a 36 month lease for a vehicle at the termination of the original auto lease. In December 2013, the Company entered into a three year lease for office space in Oklahoma City the term for which commenced in February 2014.

Rental expense totaled $44,028 and $14,595 in the three months ended June 30, 2014 and 2013, respectively and $74,967 and $28,958 for the six months ended June 30, 2014 and 2013, respectively.

Future minimum commitments under operating leases are as follows as of June 30, 2014:

Capital leases

The Company entered into a lease for certain office furniture and equipment in the first quarter of 2014. The term of the lease is three years and as the lease essentially transfer the risks of ownership it is being accounted for as a capital lease.

Leased property under capital leases at June 30, 2014 includes:

Total depreciation expense under capital leases was $6,372 and $8,496 for the three and six months ended June 30, 2014 and as of that date the future minimum lease payments under capital leases were as follows:

Legal Proceedings

The Company is not a party to any litigation that has arisen in the normal course of its business or 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. In 2010, the Company was notified by DIAN that it owed $883,742 in equity taxes relating to the 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 had lost our appeal on the 2003 tax issue and we increased the amount attributable to the 2003 tax year by $322,288 as of December 31, 2011 to correspond to the amount DIAN indicated we owed for the 2003 tax year. In January 2013, we successfully concluded negotiations with DIAN with respect to the ultimate liability for the 2003 tax year. DIAN waived certain interest and penalties. We paid the agreed final liability to DIAN in January 2013, and financed the payment with an unsecured Colombian term loan facility in the amount of $367,521. We recognized in discontinued operations the $531,644 benefit of the amnesty in the quarter ended June 30, 2013, upon receipt of official confirmation that the liability is fully settled. We repaid the unsecured Colombian term loan facility in October 2013 in conjunction with the sale of Cimarrona.

SALE OF CIMARRONA LLC

On October 7, 2013, the Company completed the sale of 100% of the membership interests in Cimarrona LLC to Raven Pipeline Company, LLC (“Raven”), pursuant to a Membership Interest Purchase Agreement dated September 30, 2013 (the “Agreement”) by and between the Company and Raven. The Cimarrona property is subject to an Ecopetrol Association Contract (the “Association Contract”) whereby Ecopetrol S.A. (“Ecopetrol”) receives royalties of 20% of the oil produced. The pipeline is not subject to the Association Contract. 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. If such an audit determines that the specified reimbursement of historical costs occurred prior to September 30, 2013, the Company is required to reimburse Raven for any amounts due to Ecopetrol from Cimarrona LLC which relate to the period prior to that date. The Company believes its maximum exposure is 50% of Cimarrona LLC’s oil revenues for the nine months ended September 30, 2013, or $729,308. The Company has not recorded any provision for this matter, as it is not possible to estimate the potential liability, if any.

9. 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 statements 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 June 30, 2014 and December 31, 2013, 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 six months ended June 30, 2014 is as follows:

10. EQUITY

Common Stock

In February 2014, the Company initiated a private placement, pursuant to Securities Purchase Agreements between Osage and certain purchasers, with aggregate gross proceeds of approximately $6.7 million. The purchase price of each unit, representing one share of common stock and a warrant to purchase 0.4 shares of common stock at $1.80 per share, was $0.90. The warrants have a term of five years. The placement agent received placement fees of 8%, in cash or warrants or a combination thereof at their election. As of June 30, 2014 units representing $6,744,000 had been sold, representing 7,493,333 shares of common stock and warrants to purchase 2,997,333 shares of common stock. The placement agent fees related to these units as of June 30, 2014 were cash fees of $427,100 and warrants to purchase 196,620 shares of common stock at $0.01 per share. In addition, the Company incurred legal fees of $10,000 with respect to the private placement.

On January 2, 2014 we issued a total of 550,000 shares to three individuals in connection with amended employment and consulting agreements. Stock based compensation had already been expensed for 150,000 shares as discussed below. The remaining 400,000 shares vest on January 1, 2015, were valued at $436,000 based on closing prices of $1.00 for 200,000 shares and $1.18 for 200,000 shares and are being expensed over one year.

On June 5, 2014 we issued a total of 600,000 non-qualified stock options to two employees and a consultant, exercisable at $0.8925 per share, with a Black-Scholes value of $629,714 and an expiration date of June 4, 2024. Variables used in the valuation include (1) discount rate of 0.85%, (2) expected life of 10 years, (3) expected volatility of 220.0% and 219.0% for employees and consultant, respectively, and (4) zero expected dividends. These options were fully vested as of the grant date.

During the three months ended March 31, 2013 we issued 400,000 shares which vested immediately to two employees with a fair value of $364,000, or $0.91 per share. 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. The 150,000 shares were valued at $177,000, or $1.18 per share, and were being expensed over the three years of the employment agreement. We recognized $14,750 of expense related to these shares in the three months ended March 31, 2013. On January 2, 2014, we amended the employment agreement and the vesting of these shares accelerated, and we recognized the unamortized portion of the stock based compensation expense in the fourth quarter of 2013.

Warrants

During the three months ended March 31, 2014, 200,000 warrants were exercised by a consultant who had previously received the warrants in exchange for services.

On April 10, 2014 we issued a warrant to purchase 2,000,000 shares of common stock to a consultant, exercisable at $1.04 per share, with a Black-Scholes value of $2,184,538 and an expiration date of April 9, 2017. Variables used in the valuation include (1) discount rate of 0.81%, (2) expected life of 3 years, (3) expected volatility of 223.0% and (4) zero expected dividends. This warrant was fully vested as of the grant date.

Total stock-based compensation expense was $2,923,252 and $26,750 for the three months ended June 30, 2014 and 2013, respectively, and $3,032,252 and $405,500 for the six months ended June 30, 2014 and 2013, respectively. All stock-based compensation expense is included in general and administrative expenses in the accompanying unaudited financial statements.

11. DISCONTINUED OPERATIONS

On October 7, 2013, the Company completed the sale of 100% of the membership interests in Cimarrona LLC to Raven, pursuant to the Agreement dated September 30, 2013 by and between the Company and Raven. Cimarrona LLC is the owner of a 9.4% interest in certain oil and gas assets including a pipeline in the Guaduas field, located in the Dindal and Rio Seco Blocks that covers 30,665 acres in the Middle Magdalena Valley in Colombia.

The sales price consisted of cash of $6,800,000, less settlement of debt of Cimarrona LLC of approximately $250,000. Of the net sales price, $250,000 will be held in escrow for 12 months to secure any post-Closing purchase price adjustments and any indemnity obligations of the Company pursuant to the Agreement. In addition, so long as the per barrel transportation rate charged with respect to the pipeline is not adjusted prior to March 31, 2014, then Raven is obligated to pay the Company an additional $1,000,000 in cash. Pursuant to the Agreement, the Company also recognized a receivable for a working capital adjustment of $422,955 in other current assets as of December 31, 2013 and recognized a gain on disposal of discontinued operations of $4,873,660 in the year ended December 31, 2013. Raven has reimbursed the Company for the working capital adjustment. The Company and Raven are in discussions about the status of the per barrel transportation rate with respect to the pipeline, and the Company does not presently have sufficient information to estimate the outcome of these discussions.

The following table sets forth the results of operations for the discontinued operations for the three and six months ended June 30, 2013: