OEDVQ Osage Exploration and Development Inc (CE)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2013 and 2012 (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 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 2012 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

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) participating in drilling of wells in Logan County, Oklahoma within the next 12 months, (b) controlling overhead and expenses, (c) selling our Colombian operations owned by our wholly owned subsidiary, Cimarrona, LLC and (d) raising additional equity and/or debt.

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 and on April 5, 2013 we amended this agreement, increasing the facility to $20,000,000. As of September 30, 2013, as a result of production delays outside of the Company’s control, the Company was not in compliance with certain covenants including the minimum production covenant under the senior secured note purchase agreement. (see Note 5 - 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 in substantial doubt and 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.

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.

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 preparation of financial statements in conformity with accounting principles accepted in the United States of America (“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 financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ 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 relates 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 there from.

Reclassifications

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

Cash and Equivalents

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

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 $3,759,448 are being amortized over the term of the Note Purchase Agreement on a straight-line basis.

Deferred financing costs at September 30, 2013 were $2,068,586. Amortization of deferred financing costs was $314,462 and $955,886 for the three and nine months ended September 30, 2013, respectively. For the three and nine months ended September 30, 2012, amortization of deferred financing costs was $272,607 and $460,509, respectively.

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 as collateral. These royalty interests at September 30, 2013 were $267,385, compared to $102,467 at December 31, 2012. The Company has also pledged $55,000 for certain bonds and sureties.

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 months and nine months ended September 30, 2013 and 2012

Potential common shares consisted of 1,696,843 and 3,071,843 warrants to purchase common stock at September 30, 2013 and 2012, respectively. 1,696,843 warrants to purchase common stock were excluded from the computations for the three and nine months ended September 30, 2013 and 1,125,000 warrants to purchase common stock were exclude from the computations for the three and nine months ended September 30, 2012, as their effect would have been anti-dilutive.

Fair Value of Financial Instruments

As of September 30, 2013 and December 31, 2012, the fair value of cash, accounts receivable and accounts payable 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 September 30, 2013 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 September 30, 2013:

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 discounted cash flow calculations 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.

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 carried 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 provided up to 17.5% of the total well costs. After the first three wells, the Company is responsible for up to 25% of the total well costs. Revenue from wells drilled pursuant to the Participation Agreement, after royalty payments, is allocated 45% to Slawson, 30% to USE and 25% to Osage. Slawson will be the operator of all wells in the Nemaha Ridge prospect in sections where the Parties’ acreage controls the section. In sections where the Parties’ acreage does not control the section, we may elect to participate in wells operated by others. 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, 2013, the Company had 8,271 net acres (48,368 gross) leased in Logan County. In December 2011, the Company began drilling its first well in Logan County and at September 30, 2013 the Company had participated, or was participating, in drilling 36 wells, 29 of which had achieved production and revenues by September 30, 2013. As of September 30, 2013, the Company had also completed four 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, 2013, the Company had 4,190 net acres (5,085 gross) leased in Pawnee County. As of September 30, 2013, none of these leases have been assigned to B&W.

In 2011, the Company began to acquire leases in Coal County, Oklahoma, targeting the Oily Woodford Shale formation. At September 30, 2013, we had 4,253 net (9,509 gross) acres leased in Coal County.

In 2013, the partners in the Participation Agreement began to acquire leases in southern Garfield County, Oklahoma, just north of the Nemaha Ridge prospect in Logan County. At September 30, 2013, we had 465 net (2,240 gross) acres leased in Garfield County.

At September 30, 2013, the Company had leased an aggregate of 17,179 net (65,202 gross) acres across four counties in Oklahoma.

4. SEGMENT AND GEOGRAPHICAL INFORMATION

At September 30, 2013, the Company operated in two segments and had activities in two geographical regions. The Oil / Gas segment engaged primarily in the acquisition, development, production and sale of oil, gas and natural gas liquids. The Pipeline segment engaged 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:

Subsequent to September 30, 2013, the Company has disposed of its Colombian operations, consisting of the entire Pipeline segment and those operations of its Oil / Gas segment located in Colombia. From October 1, 2013, the Company will operate in only one segment. Certain assets presented in the tables above have been classified as held for sale in the financial statements as of September 30, 2013. See Note 11 - Discontinued Operations and Note 12 - Subsequent Events.

5. DEBT

2013 Activity

Helm Bank, Colombia – Unsecured Term Loan

In January 2013, the Company entered into a two year unsecured term loan facility with Helm Bank, Colombia in the amount of $367,521 in order to avail of an amnesty program for certain 2003 Colombian equity taxes, as more fully discussed in Note 7. The principal is payable in 24 equal installments and the interest rate is variable. As of September 30, 2013 there was $249,315 outstanding under this term loan. The Company recognized $5,030 and $21,486 of interest expense related to this term loan in the three and nine months ended September 30, 2013, respectively.

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. In the three months ended September 30, 2013, we drew down $2,000,000 and, as of September 30, 2013, the amount outstanding under the Note Purchase Agreement was $15,000,000.

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. 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.

The Company has recorded deferred financing costs in the aggregate amount of $3,759,448 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 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 also 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.

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 amendment also provided a waiver of certain covenants as of March 31, 2013, as the Company did not meet certain covenants including the minimum production covenant as of that date. 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 12. This sale satisfied the requirements of the amendment and the Company is thus not obligated to issue additional Warrants to Apollo.

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. 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:

As of September 30, 2013, as a result of production delays outside of the Company’s control, the Company was not in compliance with certain covenants including the minimum production covenant of 35 MBbls. The Company believes Apollo will provide a waiver of these covenants as of that date. The Company has classified amounts outstanding under the Note Purchase Agreement as short term in the accompanying consolidated financial statements.

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 $1,144,948 of interest expense, of which $367,948 was non-cash interest expense and $777,000 was cash interest expense, for the three months ended September 30, 2013. For the nine months ended September 30, 2013, the Company recognized $3,041,093 of interest expense related to these facilities, of which $1,100,787 was non-cash interest expense and $1,940,306 was cash interest expense. 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.

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 three months ended September 30, 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 September 30, 2013, the Company did not hold any collateral from its counterparties.

As of September 30, 2013, 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 September 30, 2013, 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 months ended September 30, 2013.

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 September 30, 2013, 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. Apart from 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 $14,595 and $14,344 for the three months ended September 30, 2013 and 2012, respectively, and $43,553 and $42,727 for the nine month ended September 30, 2013 and 2012, respectively.

Future minimum commitments under operating leases are as follows as of September 30, 2013:

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. 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 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. The Company recognized $30,970 and $32,878 in current equity tax for the three months ended September 30, 2013 and 2012, respectively, and $95,657 and $98,481 for the nine months ended September 30, 2013 and 2012, respectively

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 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, 2013 and December 31, 2012, 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 nine months ended September 30, 2013 is as follows:

10. EQUITY

Common Stock

During the three months ended June 30, 2013, we issued a total of 10,000 shares which vest immediately to two consultants for services rendered with a fair value of $12,000, or $1.20 per share. Additionally, warrants to purchase 350,000 shares were exercised for $3,500.

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. 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. The 150,000 shares were valued at $177,000, or $1.18 per share, and are being expensed over the three years of the employment agreement. We recognized $14,750 and $44,250 of expense related to these shares in the three and nine months ended September 30, 2013, respectively.

During the three months ended September 30, 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.

During the three months ended June 30, 2012, we issued 20,000 shares of common stock at $23,000 or $1.15 per share, to a consultant as compensation for services rendered.

During the three months ended March 31, 2012, we issued 90,000 shares to a consultant for services to be provided from March through August 2012. All of the shares vested immediately with a fair value of $41,400, or $0.46 per share.

Warrants

During the three months ended June 30, 2013, warrants to purchase 350,000 shares of common stock were exercised for $3,500 and warrants to purchase 1,125,000 shares of common stock expired unexercised.

Total stock-based compensation expense was $14,750 and $13,800 for the three months ended September 30, 2013 and 2012, respectively, and $420,250 and $522,111 for the nine months ended September 30, 2013 and 2012, respectively.

11. DISCONTINUED OPERATIONS

During the three months ended September 30, 2013, the Company committed to divesting its Colombian operations held through its wholly owned subsidiary, Cimarrona, LLC. These operations consisted of the entire Pipeline segment and the portion of the Oil / Gas segment located in Colombia. Accordingly, the assets and liabilities of the Colombian operations are classified as Held for Sale in the balance sheets, with the exception of cash of $54,034 and $150,950 as of September 30, 2013 and December 31, 2012, respectively.

The following table sets forth the results of operations for the discontinued operations for the periods presented:

12. SUBSEQUENT EVENTS

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. 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 will pay the Company an additional $1,000,000 in cash within five business days of that date.

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.

As a result of this sale, the Company will operate in one segment and one geographic region effective October 1, 2013.

On October 15, 2013, the Company entered into an Intercreditor Agreement with Apollo and BP Energy Company to provide collateral for certain oil and gas derivative financial instruments more fully described in Note 6. BP Energy Corporation North America simultaneously provided a Guarantee for $25 million as collateral for its obligations.