UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

[X] QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2012

 

[ ] TRANSITION REPORT UNDER SECTION 13 OR 15(D) OF THE EXCHANGE ACT

For the transition period from _____ to _____

 

OSAGE EXPLORATION AND DEVELOPMENT, INC.

(Exact name of small business issuer as specified in its charger)

 

Delaware	0-52718	26-0421736
(State or other jurisdiction of incorporation or organization)	(Commission File No.)	(I.R.S. Employer Identification No.)

 

2445 5th Avenue Suite 310 San Diego, CA 92101 (Address of principal executive offices)

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

 

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

Yes [X] No [  ]

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes [  ] No [X]

 

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

 

Large Accelerated Filer [  ]    Accelerated Filer [  ]

Non-Accelerated Filer [  ]    Smaller Reporting Company [X]

 

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

Yes [  ] No [X]

 

The number of outstanding shares of the registrant’s Common Stock, $0.0001 par value, as of May 14, 2012 was 48,394,775.

 

 

  

OSAGE EXPLORATION AND DEVELOPMENT, INC. AND SUBSIDIARY

 

TABLE OF CONTENTS

 

			Page
PART I – FINANCIAL INFORMATION
Item 1.	Financial Statements
	Consolidated Balance Sheets; March 31, 2012 (unaudited) and December 31, 2011		F-1
	Consolidated Statements of Operations and Comprehensive Income (Loss); Three Months ended March 31, 2012 (unaudited) and March 31, 2011 (unaudited)		F-2
	Consolidated Statements of Cash Flows; Three Months ended March 31, 2012 (unaudited) and March 31, 2011 (unaudited)		F-3
	Notes to Consolidated Financial Statements		F-4
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		3
Item 3.	Quantitative and Qualitative Disclosures about Market Risk		10
Item 4.	Controls and Procedures		11
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings		12
Item 1.A.	Risk Factors		12
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		12
Item 3	Default upon Senior Securities		12
Item 4	Removed and Reserved		12
Item 5	Other Information		12
Item 6	Exhibits		12
Signatures			13

 

 

PART I. FINANCIAL INFORMATION

 

Item 1. Financial Statements

 

OSAGE EXPLORATION AND DEVELOPMENT, INC.

CONSOLIDATED BALANCE SHEETS

March 31, 2012 and December 31, 2011

 

		2012				2011
		(unaudited)
ASSETS
Current Assets:
Cash and equivalents		$	678,585			$	1,904,023
Accounts receivable			463,803				122,565
Joint operating account			74,377				235,779
Deferred financing cost			100,000				-
Prepaid expenses			129,382				57,960
Total Current Assets			1,446,147				2,320,327
Property and Equipment, at cost:
Oil and gas properties and equipment (Successful Efforts Method)			6,209,154				4,331,417
Capitalized asset retirement costs			46,146				46,146
Other property and equipment			79,942				79,942
			6,335,242				4,457,505
Less: accumulated depletion, depreciation and amortization			(1,568,705	)			(1,345,719	)
			4,766,537				3,111,786
Bank CD pledged for bond			30,000				30,000
Note Receivable			11,000				11,000
Total Assets		$	6,253,684			$	5,473,113
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable		$	529,469			$	323,699
Income taxes payable			58,093				58,893
Accrued expenses			957,778				876,545
Total Current Liabilities			1,545,340				1,259,137
Liability for Asset Retirement Obligations			60,556				59,950
Total Liabilities			1,605,896				1,319,087
Commitments and Contingencies
Stockholders' Equity:
Common stock, $0.0001 par value, 190,000,000 shares authorized; 47,974,775 and 47,884,775 shares issued and outstanding as of March 31, 2012 and December 31, 2011, respectively			4,797				4,788
Additional-Paid-in-Capital			12,149,311				12,107,920
Stock Purchase Notes Receivable			(95,000	)			(95,000	)
Accumulated Deficit			(7,102,054	)			(7,558,080	)
Accumulated Other Comprehensive Loss - Currency Translation Loss			(309,266	)			(305,602	)
Total Stockholders' Equity			4,647,788				4,154,026
Total Liabilities and Stockholders' Equity		$	6,253,684			$	5,473,113

 

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

 

  

OSAGE EXPLORATION AND DEVELOPMENT, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS AND OTHER COMPREHENSIVE INCOME (LOSS)

Three Months Ended March 31, 2012 and March 31, 2011 (unaudited)

 

		2012				2011
Operating Revenues
Oil Revenues		$	885,628			$	373,511
Pipeline Revenues			469,891				268,233
Total Operating Revenues			1,355,519				641,744
Operating Costs and Expenses:
Operating Costs			304,866				190,355
Equity Tax			32,802				-
Depreciation, Depletion and Accretion			123,630				98,818
General and Administrative Expenses			438,429				354,678
Total Operating Costs and Expenses			899,727				643,851
Operating Income (Loss)			455,792				(2,107	)
Other Income (Expenses):
Interest Income			840				229
Interest Expense			(606	)			(55,551	)
Income (Loss) before Income Taxes			456,026				(57,429	)
Provision for Income Taxes			-				-
Net Income (Loss)			456,026				(57,429	)
Other Comprehensive (Loss) Income, net of tax:
Foreign Currency Translation Adjustment			(3,664	)			6,764
Comprehensive Income (Loss)		$	452,362			$	(50,665	)
Basic and Diluted Income (Loss) per Share		$	0.01			$	(0.00	)
Weighted average number of common shares and common share equivalents used to compute basic and diluted Income (Loss) per Share			47,949,061				46,649,775

 

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

 

 

OSAGE EXPLORATION AND DEVELOPMENT, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

Three Months Ended March 31, 2012 and March 31, 2011 (unaudited)

 

		2012				2011
Cash flows from Operating Activities:
Net Income (Loss)		$	456,026			$	(57,429	)
Adjustments to reconcile net income (loss) to net cash provided by operating activites:
Shares issued for services			41,400				-
Accretion of asset retirement obligation			606				551
Provision for depletion, depreciation amortization and valuation allowance			123,630				98,818
Changes in operating assets and liabilities:
Increase in accounts receivable			(340,001	)			(108,663	)
Increase in joint operating account			135,008				59,796
(Increase)/Decrease in prepaid expenses			(71,422	)			12,855
Increase in accrued expenses			12,144				82,736
Decrease in income tax payable			(800	)			-
Increase/(Decrease) in accounts payable			202,583				(65,745	)
Net cash provided by operating activities			559,174				22,919
Cash flows from Investing Activities:
Investments in oil and gas properties			(2,689,623	)			(451,798	)
Net proceeds from assignment of leases			977,556				-
Net cash used by investing activities			(1,712,067	)			(451,798	)
Cash flows from Financing Activities:
Proceeds from secured promissory note			-				500,000
Increase in deferred financing costs			(100,000	)			-
Net cash provided/(used) by financing activities			(100,000	)			500,000
Effect of exchange rate on cash and equivalents			27,455				727
Net increase (Decrease) in cash and equivalents			(1,225,438	)			71,848
Cash and equivalents beginning of period			1,904,023				307,566
Cash and equivalents end of period		$	678,585			$	379,414
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash Payment for Interest			-				-
Cash Payment for Income Taxes			-				-
Non-Cash Transactions:
Shares issued for services		$	41,400				-

 

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

 

 

OSAGE EXPLORATION AND DEVELOPMENT, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2012 (unaudited) and December 31, 2011

 

1. ORGANIZATION AND BASIS OF PRESENTATION

 

Osage Exploration and Development, Inc. (“Osage” or the “Company”) prepared the accompanying unaudited consolidated financial statements in accordance with accounting principles generally accepted in the United States of America (“US 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 US 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.

 

Organization and Line of Business

 

Osage is an independent energy company engaged primarily in the acquisition, development, production and the sale of oil, gas and natural gas liquids. The Company’s production activities are located in the country of Colombia and in the state of Oklahoma. The principal executive offices of the Company are at 2445 Fifth Avenue, Suite 310, San Diego, CA 92101. Osage was organized 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 a business combination. Accordingly, no pro forma disclosure is made. The historical financial statements are those of Osage LLC.

 

The Nevada shell corporation was incorporated under the laws of Canada on February 24, 2003 as First Mediterranean Gold Resources, Inc. The domicile of the Company was changed to the State of Nevada on May 11, 2004. On May 24, 2004, the name of the Company was changed to Advantage Opportunity Corp. On March 4, 2005, the Company 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. On July 2, 2007, the Company 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.OB.”

 

Going Concern

 

The Company incurred losses in the last three years and has an accumulated deficit of $7,102,054 at March 31, 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 our 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 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 10 Subsequent Events).

 

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.

 

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 

Use of Estimates

 

The accompanying Interim Financial Statements have been prepared in accordance with US GAAP. 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 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 $102,828 at March 31, 2012, and at certain points throughout the period, 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% of Osage’s total revenues for the three months ended March 31, 2012 and sales to two customers comprised approximately 98% of Osage’s total revenues for the three months ended March 31, 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.

 

  

Fair Value of Financial Instruments

 

As of March 31, 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 values 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:

 

●

Level 1 inputs to the valuation methodology are quoted prices for identical assets or liabilities in active markets.

 

●

Level 2 inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, quoted prices for identical or similar assets in inactive markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

 

●

Level 3 inputs to the valuation methodology us one or more unobservable inputs which are significant to the fair value measurement.

 

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 March 31, 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 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.

 

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 March 31, 2012 and 2011, our oil production operations were conducted in Colombia and in the US. 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 three months ended March 31, 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 three months ended March 31, 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 one of our 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 unless a working interest owner’s aggregate sales from the property exceed its share of the total reserves in place. If such a situation arises, the parties would likely choose to cash balance or in some instances, the over delivered partner might choose to negotiate to buy out the under delivered party’s share. For the three months ending March 31, 2012, we recognized sales of $150,796 and 1,365 barrels in excess of production. For the three months ending March 31, 2011, there were no sales and barrels recognized in excess of production.

 

  

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 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. As of March 31, 2012, $34,500 of expense related to the shares issued was recorded as a prepaid expense and $6,900 of stock based compensation was recognized in the first quarter of 2012.

 

Total stock based compensation expense for the three months ended March 31, 2012 and 2011 was $16,500 and $0, 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. As a result of the implementation of ASC 740, the Company recognized no material adjustments to liabilities or stockholders equity.

 

When tax returns are filed, it is 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 percent likely of being realized upon settlement with the applicable taxing authority. The portion of the benefits associated with tax positions taken that exceeds the amount measured as described above is reflected as a liability for unrecognized tax benefits in the accompanying balance sheets along with any associated interest and penalties that would be payable to the taxing authorities upon examination.

 

Interest associated with unrecognized tax benefits are classified as interest expense and penalties are classified in selling, general and administrative expenses in the 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 US operations for the current period. 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 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 1,125,000 and 2,225,000 warrants to purchase common stock for the periods ended March 31, 2012 and 2011, respectively. For the three months ended March 31, 2012 and 2011, our warrants (using the treasury method) did not have a dilutive effect on our net income/loss per share calculation.

 

  

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 US 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 is 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 June 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.

 

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. ct on the consolidated financial statements.

 

Subsequent Events

 

Osage evaluated all transactions from March 31, 2012 through the financial statement issuance date for subsequent event disclosure.

 

3. OIL AND GAS PROPERTIES

 

Oil and gas properties consisted of the following:

 

		March 31,				December 31,
		2012				2011
Properties subject to amortization		$	3,060,190			$	2,215,936
Properties not subject to amortization			3,148,964				2,115,481
Capitalized asset retirement costs			46,146				46,146
			6,255,300				4,377,563
Accumulated depreciation and depletion			(1,514,370	)			(1,294,767	)
Oil & Gas Properties, Net		$	4,740,930			$	3,082,796

 

On April 21, 2011, the Company entered into a participation agreement (“Participation Agreement”) with Slawson Exploration Company (“Slawson”) and US 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 March 31, 2012, the Company had 5,959 net acres (36,363 gross) leased in Logan County. In December 2011, the Company began drilling the Wolfe 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 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 March 31, 2012, the Company had 1,674 net acres (2,591 gross) leased in Pawnee County. As of March 31, 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 March 31, 2012, we had 3,794 net (8,373 gross) acres leased in Coal County.

 

At March 31, 2012, the Company has leased an aggregate of 11,427 net acres across three counties in Oklahoma.

 

4. GEOGRAPHICAL INFORMATION

 

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

 

		Colombia				United States				Consolidated
March 31, 2012
Total Revenues		$	1,022,384			$	333,135			$	1,355,519
% of Total			75.4	%			24.6	%			100.0	%
Long Lived Assets		$	2,332,476			$	3,876,678			$	6,209,154
% of Total			37.6	%			62.4	%			100.0	%
March 31, 2011
Total Revenues		$	631,499			$	10,245			$	641,744
% of Total			98.4	%			1.6	%			100.0	%
Long Lived Assets		$	1,196,054			$	2,120,803			$	3,316,857
% of Total			36.1	%			63.9	%			100.0	%

 

5. PROMISSORY NOTE

 

On January 24, 2011, we issued a $500,000 secured promissory note to an institutional investor (“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 with the proceeds of the Participation Agreement.

 

The Company had no promissory notes outstanding as of March 31, 2012 and December 31, 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 March 31, 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 $14,039 and $13,937 for the three months ended March 31, 2012 and 2011, respectively.

 

Future minimum commitments under operating leases are as follows:

 

Year				Amount
	2012 (remainder)			$	35,815
	2013				45,494
	2014				8,190
	Thereafter				-
				$	89,499

 

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 equity value the equity tax is assessed upon, Cimarrona subtracted the cost of its non-producing wells in 2001 and 2003. However, DIAN’s position is that as long as the field is productive, Cimarrona should not have subtracted the cost of the non-producing wells. 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 $32,802 in equity tax for the three months ended March 31, 2012 and $0 for the three months ended March 31, 2011.

 

7. MAJOR CUSTOMERS

 

During the three months ended March 31, 2012 and 2011, the Company had four and three customers, respectively, which accounted for all of its sales:

 

				2012								2011
				Amount				% of Total				Amount				% of Total
	HOCOL			$	552,493				40.7	%		$	363,266				56.6	%
	Pacific				469,891				34.7	%			268,233				41.8	%
	Coffeyville				12,282				0.9	%			-				0.0	%
	Sunoco				-				0.0	%			10,245				1.6	%
	Slawson				320,853				23.7	%			-				0.0	%
	Total			$	1,355,519				100.0	%		$	641,744				100.0	%

 

8. 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 March 31, 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 from the periods presented is as follows:

 

		March 31, 2012												December 31, 2011
		Colombia				United States				Combined				Colombia				United States				Combined
Beginning Balance		$	35,719			$	24,231			$	59,950			$	35,719			$	22,227			$	57,946
Incurred during the period			-				-				-				-				-				-
Additions for new wells			-				-				-				-				-				-
Accretion expense			-				606				606				-				2,004				2,004
Ending Balance		$	35,719			$	24,837			$	60,556			$	35,719			$	24,231			$	59,950

 

  

9. EQUITY

 

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

 

There were no issuances of common stock or equivalents during the three months ended March 31, 2011.

 

10. SUBSEQUENT EVENTS

 

On April 17, 2012, we issued a $2,500,000 secured promissory note (“Secured Promissory Note”) to Boothbay Royalty Co., (“Boothbay”). The Secured Promissory Note matures April 17, 2014 and has an 18% interest rate, payable monthly. In addition, Boothbay received 400,000 shares of common stock, $0.0001 par value, a 1.5% overriding royalty on our leases in section 29, township 17 North, range 3 in Logan County, Oklahoma and a 1.7143% overriding royalty on our leases in section 36, township 19 North, range 4 West in Logan County, Oklahoma. The royalty payments are made directly by the well operator from the revenues generated by the wells, and are not an obligation of the Company. The Secured Promissory Note is secured by a First Mortgage (with Power of Sale), Security Agreement and Financing Statement, and other collateral documents of even date covering a 5% overriding royalty interest, proportionately reduced, in all of the Company’s leases in Logan County, Oklahoma.

 

On April 27, 2012, we entered into a $10,000,000 senior secured note purchase agreement (“Note Purchase Agreement”) 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 of our Oklahoma leases. The Notes have an interest rate of Libor plus fifteen percent (15%) with a Libor floor of 2.0%, with interest payable in cash monthly. In addition, Apollo received a warrant to purchase 1,496,843 shares of common stock, $0.0001 par value, exercisable at $0.01 per share with an expiration date of April 27, 2017. The fair value of this warrant will be calculated using the Black Scholes model. Minimum draw downs on the Note Purchase Agreement are $1,000,000. At closing, we did not draw down any funds.

 

At closing of the Note Purchase Agreement, we paid $100,000 placement fee, to CC Natural Resource Partners, LLC (“CCNRP”) and issued a warrant to purchase 250,000 shares of common stock, $0.0001 par value, exercisable at $0.01 per share with an expiration date of April 27, 2014. The fair value of this warrant will be calculated using the Black Scholes model. We will pay CCNRP an additional placement fee of 4.0% of the amount drawn, once we have drawn $2,500,000 under the Note Purchase Agreement.

 

On May 6, 2012, Larry Ray, a director of the Company, resigned for personal reasons.

 

  

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 2012, 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 US 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. At March 31, 2012, we had 5,959 net acres (36,363 gross) leased in Logan County. In December 2011 and January 2012, respectively, we began drilling the Wolfe 1-29H and the Krittenbrink 2-36H, our first and second wells in Logan County. In March 2012, the Company began well production and recognized its first oil revenues from these properties.

 

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 interests 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 March 31, 2012, the Company had 1,674 net acres (2,591 gross) leased in Pawnee County. As of March 31, 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 March 31, 2012, we had 3,794 net (8,373 gross) acres leased in Coal County.

 

  

At March 31, 2012, we had leased an aggregate of 11,727 net (47,327 gross) acres across three counties in Oklahoma as follows:

 

				Gross				Osage Net
	Logan				36,363				5,959
	Pawnee				2,591				1,674
	Coal				8,373				3,794
	Totals				47,327				11,427

 

We had an accumulated deficit of $7,102,054 at March 31, 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. At present, the revenues generated from the Cimarrona and Hopper 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 to Boothbay Royalty Co. 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 10 Subsequent Events, in the accompanying unaudited consolidated financial statements).

 

 

Results of Operations

 

Three Months ended March 31, 2012 compared to Three Months ended March 31, 2011

 

		Three Months Ended March 31,
		2012								2011								Change
		Amount				Percentage				Amount				Percentage				Amount				Percentage
Oil Sales		$	885,628				65.3	%		$	373,511				58.2	%		$	512,117				137.1	%
Pipeline Sales			469,891				34.7	%			268,233				41.8	%			201,658				75.2	%
Total Operating Revenues		$	1,355,519				100.0	%		$	641,744				100.0	%		$	713,775				111.2	%

 

Oil Sales

 

Oil Sales were $885,628, an increase of $512,117, or 137.1%, for the three months ended March 31, 2012 compared to $373,511 for the three months ended March 31, 2011. Oil sales increased due to an increase in the number of barrels sold as well as price increases. In Colombia, we sold 5,000 barrels (“BBLs”) at an average price of $114.51 in the 2012 period, compared to 4,000 BBLs at an average price of $94.11 in the 2011 period. In the US, we sold 4,074 BBLs at an average price of $99.51 in the 2012 period compared to 160 BBLs at an average price of $84.84 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 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 $469,891, an increase of $201,658, or 75.2% for the three months ended March 31, 2012 compared to $268,233 for the three months ended March 31, 2011, due to an increase in the number of barrels transported to approximately 2.49 million BBLs (our share was approximately 234,000 BBLs) in the 2012 period from 1.56 million BBLs (our share was approximately 147,000 BBLs) in the 2011 period.

 

Total revenues were $1,355,519, an increase of $713,775, or 111.2% for the three months ended March 31, 2012 compared to $641,744 for the three months ended March 31, 2011. Oil sales accounted for 65.3% and 58.2% of total revenues in the 2012 and 2011 periods, respectively.

 

Production

 

		Three Months Ended March 31,
		2012								2011								Increase/(Decrease)
		Net Barrels				% of Total				Net Barrels				% of Total				Barrels				%
Colombia			3,635				47.2	%			4,574				96.6	%			(939	)			-20.5	%
United States			4,074				52.8	%			160				3.4	%			3,914				2446.3	%
Total			7,709				100.0	%			4,734				100.0	%			2,975				62.8	%

 

Production, net of royalties, was 7,709 BBLs, an increase of 2,975 BBLs, or 62.8% for the three months ended March 31, 2012 compared to 4,734 BBLs for the three months ended March 31, 2011 due to production increases in the US. Colombian production accounted for 47.2% and 96.6% of total production for the three months ended March 31, 2012 and 2011, respectively.

 

  

Operating Costs and Expenses

 

		Three Months Ended March 31,
		2012								2011								Change
		Amount				Percentage				Amount				Percentage				Amount				Percentage
Operating Costs and Expenses
Operating Costs		$	304,866				22.5	%		$	190,355				29.6	%		$	114,511				60.2	%
Equity Tax			32,802				2.4	%			-				0.0	%			32,802				-
Depreciation , Depletion and Accretion			123,630				9.1	%			98,818				15.4	%			24,812				25.1	%
General & Administrative			438,429				32.4	%			354,678				55.3	%			83,751				23.6	%
Total Operating Costs and Expenses		$	899,727				66.4	%		$	643,851				100.3	%		$	255,876				39.7	%

 

Operating Costs

 

Our operating costs were $304,866 for the three months ended March 31, 2012 compared to $190,355 for the three months ended March 31, 2011, due primarily to an increase in operating costs in Colombia, which included increased pipeline expenses due to heavy rains. Operating expenses as a percentage of total revenues decreased to 22.5% in the 2012 period from 29.7% in 2011 period, as the increase in revenues was much greater than the increase in operating expenses due to successful production efforts in Oklahoma, and an increase in production as well as oil prices in Columbia.

 

General and Administrative Expenses

 

General and administrative expenses were $438,429 for the three months ended March 31, 2012, an increase of $83,751 or 23.6%, compared to $354,678 for the three months ended March 31, 2011. As a percent of total revenues, general and administrative expenses decreased to 32.3% in the 2012 period from 55.3% in the 2011 period. The increase of $83,751 was primarily due to increases in legal and professional fees of $29,700 related to financing and geological services, executive salaries and related expenses of $20,500, stock based compensation of $16,500 and Delaware franchise taxes of $8,800. The increase in stock based compensation expense of $16,500 for the three months ended March 31, 2012 related to the issuance of shares to a consultant for services. All shares were immediately vested and the value was based on the stock price at the date of issuance. Stock based compensation for the three months ended March 31, 2011 was $0.

 

Depreciation, depletion and accretion

 

Depreciation, depletion and accretion were $123,630 for the three months ended March 31, 2012 and $98,818 for the three months ended March 31, 2011, an increase of $24,812 or 25.1%. Our depletion expense will continue to increase to the extent we are successful in our well production in Oklahoma.

 

Equity Tax

 

Division de Impuestos y Actuanas Nacionales (“DIAN”), the Colombian tax authorities, levies a tax based on the equity value of Cimarrona. Equity tax was $32,802 for the three months ended March 31, 2012 and $0 for the three months ended March 31, 2011.

 

Income/Loss from Operations

 

Income from operations was $455,792 for the three months ended March 31, 2012 compared to a loss of $2,107 for the three months ended March 31, 2011. The improvement in operating results of $457,899 was due to the increase in revenues of $713,775 for the three months ended March 31, 2012 compared to the three months ended March 31, 2011, offset by the $255,876 increase in operating expenses during the same periods.

 

  

Interest Expense

 

Interest expense was $606 for the three months ended March 31, 2011 compared to $55,551 for the three months ended March 31, 2011, a decrease of $54,945. Interest expense for the 2011 period is for the Blackrock Promissory Note issued in January 2011 and repaid in May 2011.

 

Provision for Income Taxes

 

Provision for income taxes was zero for the three months ended March 31, 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 US operations for the current period.

 

Net Income/Loss

 

Net income was $456,026 for the three months ended March 31, 2012 compared to a net loss of $57,429 for the three months ended March 31, 2011. The $513,455 improvement in net loss is due to the $457,899 improvement in income from operations and the $54,945 decrease in interest expense in the 2012 period compared to the 2011 period.

 

Foreign Currency Translation Gain/Loss

 

Foreign currency translation loss was $3,664 for the three months ended March 31, 2012 compared to a gain of $6,764 for the three months ended March 31, 2011. The Colombian Peso to Dollar Exchange Rate averaged 1,800 and 1,881 for the three months period ended March 31, 2012 and 2011, respectively and was 1,791 and 1,878 at March 31, 2012 and December 31, 2011.

 

Comprehensive Income/Loss

 

Comprehensive income was $452,362 for the three months ended March 31, 2012 compared to a comprehensive loss of $50,665 for the three months ended March 31, 2011. Comprehensive income improved by $503,027 due to the $513,455 improvement in net income in the 2012 period compared to the 2011 period and slightly offset by the $10,428 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 $559,174 for the three months ended March 31, 2012, compared to $22,919 for the three months ended March 31, 2011. The major components of net cash provided by operating activities for the three months ended March 31, 2012 was the $349,735 increase in accounts payable and accrued expenses due primarily to our Oklahoma operations related to well production and drilling and the $123,630 provision for depreciation, depletion and amortization. The major components of the net cash provided by operating activities for the three months ended March 31, 2011 were $98,818 provision for depreciation and depletion and $76,787 increase in accounts payable and accrued expenses, offset by $108,663 increase in accounts receivable and $57,429 net loss.

 

Net cash used in investing activities totaled $1,712,067 for the three months ended March 31, 2012 and consisted of investments in additional leases in the Mississippian and other formations in Oklahoma, partially offset by proceeds from lease assignments. Net cash used in investing activities for the three months ended March 31, 2011 totaled $451,798 and consisted mostly of investments in additional Mississippian leases.

 

Net cash used in financing activities totaled $100,000 for the three months ended March 31, 2012 and consisted of deferred financing costs related to the Note Purchase Agreement with Apollo. Net cash provided by financing activities totaled $500,000 for the three months ended March 31, 2011 and consisted entirely of the Blackrock Promissory Note.

 

Net operating revenues from our oil production are very sensitive to changes in the price of oil making it very difficult for management to predict whether or not we will be profitable in the future.

 

  

We conduct no product research and development. Any expected purchase of significant equipment is directly related to drilling operations and the completion of successful wells.

 

We operate our Osage Property through independent contractors that operate producing wells for several small oil companies. Pacific Rubiales owns 90.6% of the Guaduas field and is the operator.

 

We are responsible for any contamination of land we own or lease. However, we carry pollution liability insurance policies, which may limit some potential contamination liabilities as well as claims for reimbursement from third parties.

 

Effect of Changes in Prices

 

Changes in prices during the past few years have been a significant factor in the oil and gas (“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 and Coffeyville in the US. 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 Osage property, we sold oil at prices ranging from $99.51 to $105.22 per barrel during the three months ended March 31, 2012 compared to $84.84 per barrel during the three month ended March 31, 2011. In our Cimarrona property in Colombia, we sold oil at prices ranging from $107.65 to $119.00 per barrel during the three months ended March 31, 2012 compared to $82.21 to $105.58 during the three months ended March 31, 2011. The Colombian Peso to Dollar Exchange Rate averaged approximately 1,800 and 1,878 during the three months ended March 31, 2012 and 2011, respectively. The Colombian Peso to Dollar Exchange Rate was 1,791 and 1,882 at March 31, 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 three months ended March 31, 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 March 31, 2012 and 2011, our oil production operations were conducted in Colombia and in the US. 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

 

·

an obligation under a guarantee contract,

·

a retained or contingent interest in assets transferred to the unconsolidated entity or similar arrangement that serves as credit, liquidity or market risk support to such entity for such assets,

·

any obligation, including a contingent obligation, under a contract that would be accounted for as a derivative instrument, or

·

any obligation, including a contingent obligation, arising out of a variable interest in an unconsolidated entity that is held by us and material to us where such entity provides financing, liquidity, market risk or credit risk support to, or engages in leasing, hedging or research and development services with us.

 

Item 3. Quantitative and Qualitative Disclosures about Market Risk

 

Our company is a Smaller Reporting Company. A Smaller Reporting Company is not required to provide the disclosure information required by this item.

 

  

Item 4. Controls and Procedures

 

The Company’s management, including 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 offers, as appropriate to allow timely decisions regarding required disclosure.

 

Management conducted an assessment of the effectiveness of the Company’s internal control over financial reporting (“ICFR”) as of March 31, 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 March 31, 2012 is not effective. Based on this assessment, management has determined that, as of March 31, 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 US 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 March 31, 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 its common stock at $41,400 or $0.46 per share to a consultant as compensation for services to be rendered March 2012 through August 2012.

 

The issuance of the securities of the Company in the above transaction 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 transaction 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.

 

	OSAGE EXPLORATION AND DEVELOPMENT, INC. (Registrant)
Date: May 15, 2012	By:	/s/ Kim Bradford
		Kim Bradford
		President and Chief Executive Officer

 

Date: May 15, 2012	By:	/s/ Kim Bradford
		Kim Bradford
		Principal Financial Officer

 

  

EXHIBIT INDEX

 

The following is a list of Exhibits required by Item 601 of Regulation S-K. Except for these exhibits indicated by an asterisk which are filed herewith, the remaining exhibits below are incorporated by reference to the exhibit previously filed by us as indicated.

 

Exhibit No.		Description
3.1		Articles of Incorporation of Osage Exploration and Development, Inc. (1)
3.2		Bylaws of Osage Exploration and Development, Inc. (2)
31.1 (*)		Certification pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, signed by Kim Bradford, President and Chief Executive Officer (Principal Executive Officer)
31.2 (*)		Certification pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, signed by Kim Bradford, Chief Financial Officer (Principal Financial Officer).
32.1 (*)		Certification pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, signed by Kim Bradford, President and Chief Executive Officer (Principal Executive Officer and Principal Financial Officer).
101.INS(*)		XBRL Instance Document
101.SCH(*)		XBRL Taxonomy Extension Schema
101.CAL(*)		XBRL Taxonomy Extension Calculation Linkbase
101.DEF(*)		XBRL Taxonomy Extension Definition Linkbase
101.LAB(*)		XBRL Taxonomy Extension Label Linkbase
101.PRE(*)		XBRL Taxonomy Presentation Linkbase

 

(1)

Incorporated herein by reference to Exhibit 3.1 to the Osage Exploration and Development, Inc. Form 10-SB Amendment No. 1 filed August 27, 2007

(2)

Incorporated herein by reference to Exhibit 3.2 to the Osage Exploration and Development, Inc. Form 10-SB Amendment No. 1 filed August 27, 2007