Attached files
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, 2011
o TRANSITION REPORT UNDER SECTION 13 OR 15(D) OF THE EXCHANGE ACTFor the transition period from _____ to _____
OSAGE EXPLORTION AND DEVELOPMENT, INC.
(Exact name of small business issuer as specified in its charger)
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Delaware
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0-52718
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26-0421736
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(State or other jurisdiction of incorporation or organization)
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(Commission File No.)
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(I.R.S. Employer Identification No.)
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2445 5th Avenue
Suite 310
San Diego, CA 92101
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(619) 677-3956
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(Address of principal executive offices)
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(Issuer’s telephone number)
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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 o
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 o 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 | o | Accelerated Filer | o |
| Non-Accelerated Filer | o | 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 o No x
The number of outstanding shares of the registrant’s Common Stock, $0.0001 par value, as of May 12, 2011 was 46,899,775.
OSAGE EXPLORATION AND DEVELOPMENT, INC. AND SUBSIDIARY
TABLE OF CONTENTS
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CONSOLIDATED BALANCE SHEETS
March 31, 2011 and December 31, 2010
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2011
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2010
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ASSETS
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(unaudited)
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Current Assets:
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Cash and equivalents
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$ | 379,414 | $ | 307,566 | ||||
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Accounts receivable
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118,627 | 74,678 | ||||||
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Prepaid expenses
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26,586 | 39,441 | ||||||
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Total Current Assets
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524,627 | 421,685 | ||||||
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Property and Equipment, at cost:
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Oil and gas properties and equipment
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3,316,857 | 2,818,833 | ||||||
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Capitalized asset retirement costs
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46,146 | 46,146 | ||||||
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Other property & equipment
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54,861 | 54,861 | ||||||
| 3,417,864 | 2,919,840 | |||||||
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Less: accumulated depletion, depreciation and amortization
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(1,057,009 | ) | (939,639 | ) | ||||
| 2,360,855 | 1,980,201 | |||||||
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Bank CD pledged for bond
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30,000 | 30,000 | ||||||
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Total Assets
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$ | 2,915,482 | $ | 2,431,886 | ||||
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LIABILITIES AND STOCKHOLDERS’ EQUITY
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Current Liabilities:
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Accounts payable
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$ | 134,277 | $ | 202,880 | ||||
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Accrued expenses
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974,621 | 872,308 | ||||||
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Current maturity of promissory note
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500,000 | — | ||||||
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Total Current Liabilities
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1,608,898 | 1,075,188 | ||||||
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Liability for Asset Retirement Obligations
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58,297 | 57,746 | ||||||
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Total Liabilities
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1,667,195 | 1,132,934 | ||||||
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Commitments and Contingencies
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Stockholders’ Equity:
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Common stock, $0.0001 par value, 190,000,000 shares authorized; 46,649,775 shares issued and outstanding
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4,665 | 4,665 | ||||||
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Additional-Paid-in-Capital
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11,795,844 | 11,795,844 | ||||||
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Stock Purchase Notes Receivable
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(95,000 | ) | (95,000 | ) | ||||
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Accumulated Deficit
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(10,151,108 | ) | (10,093,679 | ) | ||||
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Accumulated Other Comprehensive Loss - Currency Translation Loss
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(306,114 | ) | (312,878 | ) | ||||
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Total Stockholders’ Equity
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1,248,287 | 1,298,952 | ||||||
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Total Liabilities and Stockholders’ Equity
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$ | 2,915,482 | $ | 2,431,886 | ||||
The accompanying notes are an integral part of these consolidated financial statements.
1
OSAGE EXPLORATION AND DEVELOPMENT, INC.
Three Months Ended March 31, 2011 and March 31, 2010 (unaudited)
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2011
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2010
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Operating Revenues
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Oil Revenues
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$ | 373,511 | $ | 317,470 | ||||
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Pipeline Revenues
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268,233 | 107,293 | ||||||
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Total Operating Revenues
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641,744 | 424,763 | ||||||
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Operating Costs and Expenses
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Operating Expenses
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190,355 | 135,136 | ||||||
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Depreciation, Depletion and Accretion
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98,818 | 90,625 | ||||||
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General and Administrative Expenses
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354,678 | 1,202,049 | ||||||
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Total Operating Costs and Expenses
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643,851 | 1,427,810 | ||||||
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Operating (Loss)
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(2,107 | ) | (1,003,047 | ) | ||||
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Other Income (Expenses):
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Interest Income
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229 | 1,392 | ||||||
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Interest Expense
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(55,551 | ) | (537 | ) | ||||
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(Loss) before Income Taxes
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(57,429 | ) | (1,002,192 | ) | ||||
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Provision for Income Taxes
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— | — | ||||||
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Net (Loss)
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(57,429 | ) | (1,002,192 | ) | ||||
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Other Comprehensive (Loss)/Income, net of tax:
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Foreign Currency Translation Adjustment
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6,764 | (15,344 | ) | |||||
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Comprehensive (Loss)
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$ | (50,665 | ) | $ | (1,017,536 | ) | ||
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Basic and Diluted Loss per Share
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$ | (0.00 | ) | $ | (0.02 | ) | ||
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Weighted average number of common share and common share equivalents used to compute basic and dilluted Loss per Share
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46,649,775 | 46,193,108 | ||||||
The accompanying notes are an integral part of these consolidated financial statements.
2
OSAGE EXPLORATION AND DEVELOPMENT, INC.
Three Months Ended March 31, 2011 and March 31, 2010 (unaudited)
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2011
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2010
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Cash flows from Operating Activities:
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Net (Loss)
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$ | (57,429 | ) | $ | (1,002,192 | ) | ||
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Adjustments to reconcile net (loss) to net cash provided by operating activites:
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Accretion of Asset Retirment Obligation
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551 | 501 | ||||||
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Provision for depletion, depreciation amortization and valuation allowance
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98,818 | 90,625 | ||||||
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Changes in operating assets and liabilities:
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(Increase)/Decrease in accounts receivable
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(108,663 | ) | 144,621 | |||||
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Decrease in other current assets
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— | 282 | ||||||
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Decrease in prepaid expenses
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12,855 | 15,987 | ||||||
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Increase in accounts payable and accrued expenses
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76,787 | 798,709 | ||||||
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Net cash provided by operating activities
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22,919 | 48,533 | ||||||
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Cash flows from Investing Activities:
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Investments in Oil & Gas Properties
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(451,798 | ) | (9,531 | ) | ||||
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Net cash (used) by investing activities
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(451,798 | ) | (9,531 | ) | ||||
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Cash flows from Financing Activities:
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Proceeds from Secured Promissory Note
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500,000 | — | ||||||
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Payments on Promissory Note
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— | (983 | ) | |||||
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Net cash provided/(used) by financing activities
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500,000 | (983 | ) | |||||
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Effect of exchange rate on cash and equivalents
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727 | (15,344 | ) | |||||
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Net increase in cash and equivalents
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71,848 | 22,675 | ||||||
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Cash and equivalents beginning of period
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307,566 | 1,174,989 | ||||||
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Cash and equivalents at end of period
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$ | 379,414 | $ | 1,197,664 | ||||
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SUPPLEMENTAL CASH FLOW INFORMATION:
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Cash Payment for Interest
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— | 35 | ||||||
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Cash Payment for Income Taxes
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— | — | ||||||
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Non-Cash Transactions:
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Cancellation of shares for notes receivable
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— | 25,000 | ||||||
The accompanying notes are an integral part of these consolidated financial statements.
3
OSAGE EXPLORATION AND DEVELOPMENT, INC. AND SUBSIDIARIES
March 31, 2011 (unaudited) and December 31, 2010
1. 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 (“USA”) for interim financial information and pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) instructions to Form 10-Q and Item 310(b) of regulation S-K. These financial statements should be read together with the financial statements and notes in the Company’s 2010 Form 10-K filed with the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles (“GAAP”) in the USA were condensed or omitted. The accompanying financial statements reflect all adjustments and disclosures, which, in the Company’s opinion, are necessary for fair presentation. All such adjustments are of a normal recurring nature. The results of operations for the interim periods are not necessarily indicative of the results of the entire year.
Going Concern
The Company incurred significant losses in the last three years, as well as the three months ended March 31, 2011 and has an accumulated deficit of $10,151,108 at March 31, 2011 and $10,093,679 (audited) at December 31, 2010. 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 that may take the form of debt or equity financings. There is no assurance that additional funds will be available. The Company's ability to continue as a going concern is in substantial doubt and is dependent upon achieving a profitable level of operations and obtaining additional financing.
Management of our Company has undertaken steps as part of a plan to improve operations with the goal of sustaining our operations for the next twelve months and beyond. These steps include (a) attempting to increase our current production in the Osage and Cimarrona properties, (b) controlling overhead and expenses and (c) raising additional capital and/or obtaining financing.
There is no assurance the Company can accomplish these steps and it is uncertain the Company will achieve a profitable level of operations and obtain additional financing. There is no assurance that additional financings will be available to the Company on satisfactory terms and conditions, if at all. In the event we are unable to continue as a going concern, we may elect or be required to seek protection from our creditors by filing a voluntary petition in bankruptcy or may be subject to an involuntary petition in bankruptcy. To date, management has not considered this alternative, nor does management view it as a likely occurrence.
These consolidated financial statements do not give effect to any adjustments which would be necessary should the Company be unable to continue as a going concern and therefore be required to realize its assets and discharge its liabilities in other than the normal course of business and at amounts different from those reflected in the accompanying consolidated financial statements.
IMPACT OF RECENT ACCOUNTING PRONOUNCEMENTS
Recent Pronouncements
In June 2009, the FASB issued Financial Accounting Standard No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles – a replacement of FASB Statement No. 162” (“FAS 168”). In addition, in September 2009, the FASB issued Accounting Standards Update No. 2009-01, “Topic 205 – Generally Accepted Accounting Principles - amendments based on Statement of Financial Accounting Standards No. 168 – The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles” (“ASU 2009-1”). Both FAS 168 and ASU 2009-1 recognize the FASB Accounting Standards Codification as the source of authoritative U.S. GAAP to be utilized by nongovernmental entities. FAS 168 and ASU 2009-1 are effective for interim and annual periods ending after September 15, 2009. The adoption of this pronouncement did not have a material impact on the Company’s financial statements.
4
In May 2009, the FASB issued FASB No. 165, “Subsequent Events” (“SFAS 165”), as codified by FASB ASC topic 855(“ASC 855”). ASC 855 establishes general standards of accounting for disclosing events that occur after the balance sheet date but before financial statements are issued or are available to be issued. It requires the disclosure of the date through which an entity has evaluated subsequent events and the basis for selecting that date, that is, whether that date represents the date the financial statements were issued or were available to be issued. ASC 855 is effective for interim or annual financial periods ending after September 15, 2009. The adoption of ASC 855 did not have a material impact on the Company.
In June 2009, the FASB issued FASB No. 166, “Accounting for Transfers of Financial Assets - an amendment of FASB Statement No. 140” (“SFAS 166”), as codified by FASB ASC topic 860 (“ASC 860”). ASC 860 requires additional disclosures about the transfer and derecognition of financial assets and eliminates the concept of qualifying special-purpose entities under SFAS 140. ASC 860 is effective for fiscal years beginning after November 15, 2009. The adoption of ASC 860 did not have a material impact on the Company.
In June 2009, the FASB issued SFAS No. 167, “Amendments to FASB Interpretation No. 46(R)” (“SFAS 167”). SFAS 167 amends certain requirements of FASB Interpretation No. 46 (revised December 2003), “Consolidation of Variable Interest Entities”, as codified by FASC ASC topic 810 (“ASC 810”) to improve financial reporting by enterprises involved with variable interest entities and to provide more relevant and reliable information to users of financial statements. This Statement is effective as of the beginning of each reporting entity’s first annual reporting period that begins after November 15, 2009, for interim periods within that first annual reporting period, and for interim and annual reporting periods thereafter. The adoption of ASC 810 did not have a material impact on its results of operations or financial position.
All new accounting pronouncements issued but not yet effective have been deemed to not be applicable, hence the adoption of these new standards is not expected to have a material impact on the consolidated financial statements.
Income Tax
The Company follows FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes,” as codified by FASB ASC topic 740 (“ASC 740”). As a result of the implementation of ASC 740, the Company made a comprehensive review of its portfolio of tax positions in accordance with recognition standards established by ASC 740. As a result of the implementation of ASC 740, the Company recognized no material adjustments to liabilities or stockholders equity.
When tax returns are filed, it is likely certain that some positions taken would be sustained upon examination by the taxing authorities, while others are subject to uncertainty about the merits of the position taken or the amount of the position that would be ultimately sustained. The benefit of a tax position is recognized in the financial statements in the period during which, based on all available evidence, management believes it is more likely than not that the position will be sustained upon examination, including the resolution of appeals or litigation processes, if any. Tax positions taken are not offset or aggregated with other positions. Tax positions that meet the more-likely-than-not recognition threshold are measured as the largest amount of tax benefit that is more than 50 percent likely of being realized upon settlement with the applicable taxing authority. The portion of the benefits associated with tax positions taken that exceeds the amount measured as described above is reflected as a liability for unrecognized tax benefits in the accompanying balance sheets along with any associated interest and penalties that would be payable to the taxing authorities upon examination.
Interest associated with unrecognized tax benefits are classified as interest expense and penalties are classified in selling, general and administrative expenses in the statements of income.
The Company did not have a provision for income taxes for 2011 or 2010. Due to a history of operating losses, the Company records a full valuation allowance against its net deferred tax assets and therefore recorded no tax provision related to its US operations for the current period.
5
Oil and gas properties consisted of the following as of March 31, 2011 and December 31, 2010:
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2011
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2010
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Properties subject to amortization
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$ | 2,274,247 | $ | 2,225,369 | ||||
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Properties not subject to amortization
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1,042,610 | 593,464 | ||||||
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Capitalized asset retirement costs
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46,146 | 46,146 | ||||||
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Accumulated depreciation and depletion
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(1,013,140 | ) | (897,833 | ) | ||||
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Oil & Gas Properties, Net
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$ | 2,349,863 | $ | 1,967,146 | ||||
3. GEOGRAPHICAL INFORMATION
The following table sets forth revenues for the periods reported and assets by geographic location:
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Colombia
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United States
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Consolidated
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March 31, 2011
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Total Revenues
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$ | 631,499 | $ | 10,245 | $ | 641,744 | ||||||
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% of Total
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98.4 | % | 1.6 | % | 100.0 | % | ||||||
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Long Lived Assets
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$ | 1,196,054 | $ | 2,120,803 | $ | 3,316,857 | ||||||
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% of Total
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36.1 | % | 63.9 | % | 100.0 | % | ||||||
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March 31, 2010
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Total Revenues
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$ | 388,528 | $ | 36,235 | $ | 424,763 | ||||||
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% of Total
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91.5 | % | 8.5 | % | 100.0 | % | ||||||
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Long Lived Assets
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$ | 1,605,895 | $ | 149,168 | $ | 1,755,063 | ||||||
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% of Total
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91.5 | % | 8.5 | % | 100.0 | % | ||||||
5. PROMISSORY NOTE
On April 27, 2007, we purchased a truck to be used by our pumper in our Oklahoma properties by issuing a promissory note (the “Promissory Note”) to a bank secured by the truck. The Promissory Note had a variable interest rate of Prime plus 1.0% and monthly principal and interest payments totaling $366. The Promissory Note matured and was paid off on October 27, 2010.
On January 24, 2011, we issued a $500,000 secured promissory note to an institutional investor (“Blackrock Note”) for $500,000. The Secured Promissory Note matures May 24, 2011, has a loan fee of $100,000, payable at the time of repayment, and is secured by an assignment of all of our current and future leases in Logan County, OK and the Company's 100% ownership in Cimarrona LLC.
6
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 that it believes is customary in the industry, although it is not fully insured against all environmental risks.
The Company is not aware of any environmental claims existing as of March 31, 2011, that would have a material impact on its consolidated financial position or results of operations. There can be no assurance, however, that current regulatory requirements will not change, or past non-compliance with environmental laws will not be discovered on the Company's property.
LAND RENTALS AND OPERATING LEASES
In February 2008, the Company entered into a 36 month lease for its corporate offices in San Diego. The lease, including parking, was initially for $3,682 per month for the first year, increasing to $3,800 and $3,923 in the second and third year respectively. The lease was guaranteed by Mr. Bradford, our President, CEO and CFO. No compensation was given to Mr. Bradford for his guarantee. In addition, the Company is responsible for all operating expenses and utilities.
In February 2011, the Company amended the lease for another three years, including parking, with initial payments of $3,488 per month for the first year, increasing to $3,599 and $3,715 in the second and third year, respectively. The amended lease released Mr. Bradford of his guarantee, but required the Company to increase its security deposit from $3,381 to $10,000, with $3,299 and $3,415 of the security deposit to be applied to months 13 and 25, respectively, of the lease. Outside of the San Diego lease, the Company’s Oklahoma office and all equipment leased are under month-to-month operating leases.
Future minimum rental payments required as of March 31, 2011 under operating leases are as follows by year:
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Year
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Amount
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2011
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$
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31,392
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2012
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39,778
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2013
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41,049
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2014
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3,715
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2015
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—
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Totals
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$
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115,934
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Rental expense charged to operations totaled $13,937 and $13,454 in 2011 and 2010, respectively.
LEGAL PROCEEDINGS
The Company is not a party to any litigation that has arisen in the normal course of its business and that of its subsidiaries.
7
The Company recorded an $860,937 charge in General and Administrative Expenses in 2010 as, in the first quarter of 2010, we were notified by Division de Impuestos y Actuanas Nacionales (“DIAN”), the Colombian tax authorities, that Cimarrona owes $860,937 for taxes assessed on its equity value relating to its operations in 2001 and 2003 prior to its ownership by us. In order to compute the equity value the equity tax is assessed upon, Cimarrona subtracted the cost of its non-producing wells in 2001 and 2003. However, DIAN’s position is that as long as the field is productive, Cimarrona should not have subtracted the cost of the non-producing wells. The Company is appealing DIAN’s decision but in the event the Company loses its appeal, it believes it may need to begin paying the 2001 taxes by the second quarter of 2011 and the 2003 taxes by the end of 2011 or the beginning of 2012. The Company believes that, in the event it loses its appeal, it may be able to make these tax payments over a three to seven year period.
7. MAJOR CUSTOMERS
During 2011 and 2010, the Company had three customers that accounted for all of its sales.
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2011 Revenues
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2010 Revenues
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Hocol
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$
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363,266
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56.6
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%
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$
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281,235
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66.2
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%
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|||||
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Pacific
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268,233
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41.8
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%
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107,293
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25.3
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%
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|||||||
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Sunoco
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10,245
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1.6
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%
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36,235
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8.5
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%
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|||||||
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Totals
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$
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641,744
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100.0
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%
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$
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424,763
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100.0
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%
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|||||
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 to the extent that the liability exists on the balance sheet. Differences between the actual costs incurred and the fair value of the liability recorded are recognized in income in the period the actual costs are incurred.
There are no legally restricted assets for the settlement of asset retirement obligations. A reconciliation of the Company's asset retirement obligations for the periods presented is as follows:
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March 31, 2011
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December 31, 2010
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Colombia
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United States
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Combined
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Colombia
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United States
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Combined
|
|||||||||||||||||||
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Beginning Balance
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$ | 35,719 | $ | 22,027 | $ | 57,746 | $ | 35,719 | $ | 20,023 | $ | 55,742 | ||||||||||||
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Incurred during the period
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— | — | — | — | — | — | ||||||||||||||||||
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Additions for new wells
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— | — | — | — | — | — | ||||||||||||||||||
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Accretion expense
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— | 551 | 551 | — | 2,004 | 2,004 | ||||||||||||||||||
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Ending Balance
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$ | 35,719 | $ | 22,578 | $ | 58,297 | $ | 35,719 | $ | 22,027 | $ | 57,746 | ||||||||||||
8
9. SUBSEQUENT EVENTS
On April 5, 2011, we issued a $200,000 secured promissory note (“Secured Promissory Note”) to Peter Hoffman (“Hoffman”), an individual investor for $200,000. The Secured Promissory Note matures August 5, 2011, has a loan fee and prepaid interest of 250,000 shares of common stock, $0.0001 par value, and is secured by an assignment of the Company’s future oil and gas leases in Logan County, OK. The Company is only allowed to use the proceeds from the Secured Promissory Note to acquire additional oil and gas leases.
In addition, the Company amended its Blackrock Note to allow Hoffman to receive, as collateral, all future oil and gas leases in Logan County, OK. The Company further agreed that, as long as the Blackrock Secured Promissory Note is outstanding, it will keep a minimum of $50,000 in the bank account of Cimarrona, LLC as collateral for the Blackrock Note.
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 is the owner of a 9.4% interest in certain oil and gas assets in the Guaduas field, located in the Dindal and Rio Seco Blocks that consist of twenty one wells, of which seven are currently producing, that covers 30,665 acres in the Middle Magdalena Valley in Colombia as well as a pipeline with a current capacity of approximately 30,000 barrels of oil per day. The Purchase Agreement was effective as of April 1, 2008.
The Cimarrona property, but not the pipeline, is subject to an Ecopetrol Association Contract (the “Association Contract”) whereby we pay Ecopetrol S.A. (“Ecopetrol”) royalties of 20% of the oil produced. The royalty amount is paid in oil. In addition to the royalty, according to the Association Contract, Ecopetrol may, for no consideration, become a 50% partner, once an audit of revenues and expenses indicate that the partners in the Association Contract have a received a 200% reimbursement of all historical costs to develop and operate the Guaduas field. We believe that Ecopetrol could become a 50% partner in 2011 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.
9
In 2010, the Company 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 1,000 feet in gross thickness and the targeted porosity zone is between 50 and 250 feet in thickness. 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, the application of horizontal cased-hole drilling and multi-stage hydraulic fracturing treatments have demonstrated the potential for extracting significant additional quantities of oil and natural gas from the formation.
The Company has acquired oil and gas leases covering approximately 8,585 and 5,364 net acres as of March 31, 2011 and December 31, 2010, respectively. The Company intends to focus most of its efforts and resources in 2011 on acquiring additional leases and attempting to find a partner in order to develop this acreage. We have yet to drill any wells and, therefore, have no basis to estimate whether such properties will produce oil and natural gas in sufficient quantities so as to be profitable or at all.
We anticipate we will need to raise at least $2,000,000 to provide for requirements for the next twelve months. At present, the revenues generated from our properties are only sufficient to cover field operating expenses and a small portion of our overhead.
We have undertaken steps as part of a plan to improve operations with the goal of sustaining our operations for the next twelve months and beyond. These steps include (a) raising additional capital and/or obtaining financing; (b) increasing our current production in the Osage and Cimarrona properties and (c) controlling overhead and expenses.
There is no assurance we will successfully accomplish these steps and it is uncertain we will achieve a profitable level of operations and/or obtain additional financing. There can be no assurance that any additional financings will be available to us on satisfactory terms and conditions, if at all. In the event we are unable to continue as a going concern, we may elect or be required to seek protection from our creditors by filing a voluntary petition in bankruptcy or may be subject to an involuntary petition in bankruptcy. To date, management has not considered this alternative, nor does management view it as a likely occurrence.
Results of Operations
Three Months ended March 31, 2011 compared to Three Months ended March 31, 2010
|
2011
|
2010
|
Change
|
|||||||||||||||||
|
Amount
|
Percentage
|
Amount
|
Percentage
|
Amount
|
Percentage
|
||||||||||||||
|
Oil Sales
|
$
|
373,511
|
58.2
|
%
|
$
|
317,470
|
74.7
|
%
|
$
|
56,041
|
17.7
|
%
|
|||||||
|
Pipeline Sales
|
268,233
|
41.8
|
%
|
107,293
|
25.3
|
%
|
160,940
|
150.0
|
%
|
||||||||||
|
Total Revenues
|
$
|
641,744
|
100.0
|
%
|
$
|
424,763
|
100.0
|
%
|
$
|
216,981
|
51.1
|
%
|
|||||||
Oil Sales
Oil Sales were $373,511, an increase of $56,041, or 17.7%, in 2011 compared to $317,470 in 2010. The increase is due primarily to an increase in oil prices, offset by a decrease in unit sales in the United States. In Colombia, we sold 4,000 barrels (“BBLs”) at an average gross price of $94.11 in 2011, compared to 4,000 BBLs at an average gross price of $72.86 in 2010. In the United States, we sold 160 BBLs at an average gross price of $84.84 in 2011 compared to 653 BBLs at an average gross price of $73.62 in 2010.
10
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 $268,233, an increase of $160,940, or 150.0% in 2011 compared to $107,293 in 2010 due to a large increase in the number of barrels transported to approximately 1.56 million BBLs (our share was approximately 147,000 BBLs) in 2011 from 0.68 million BBLs (our share was approximately 63,000 BBLs) in 2010. In 2010, the ODC Pipeline was operating at close to full capacity, and in certain weeks, at full capacity, which severely restricted our ability to transport oil over our pipeline.
Total revenues were $641,744, an increase of $216,981, or 51.1% in 2011 compared to $424,763 in 2010. Oil sales accounted for 58.2% and 74.7% of total revenues in 2011 and 2010, respectively.
Production
|
2011
|
2010
|
Increase/(Decrease)
|
|||||||||||||||||
|
Net Barrels
|
% of Total
|
Net Barrels
|
% of Total
|
Barrels
|
%
|
||||||||||||||
|
Colombia
|
4,574
|
96.6
|
%
|
4,940
|
88.3
|
%
|
(366
|
)
|
-7.4
|
%
|
|||||||||
|
United States
|
160
|
3.4
|
%
|
653
|
11.7
|
%
|
(493
|
)
|
-75.5
|
%
|
|||||||||
|
Total
|
4,734
|
100.0
|
%
|
5,593
|
100.0
|
%
|
(859
|
)
|
-15.4
|
%
|
|||||||||
Production, net of royalties, was 4,734 BBLs, a decrease of 859 BBLs, or 15.4% in 2011 compared to 5,593 BBLs in 2010 due to production decreases in both Colombia and the United States. Colombian production accounted for 96.6% and 88.3% of total production in 2011 and 2010, respectively.
Operating Costs and Expenses
|
2011
|
2010
|
Change
|
|||||||||||||||||
|
Amount
|
Percentage
|
Amount
|
Percentage
|
Amount
|
Percentage
|
||||||||||||||
|
Operating Expenses
|
|||||||||||||||||||
|
Operating Expenses
|
$
|
190,355
|
29.7
|
%
|
$
|
135,136
|
31.8
|
%
|
$
|
55,219
|
40.9
|
%
|
|||||||
|
Depreciation , Depletion and Accretion
|
98,818
|
15.4
|
%
|
90,625
|
21.3
|
%
|
8,193
|
9.0
|
%
|
||||||||||
|
General & Administrative Expenses
|
354,678
|
55.3
|
%
|
1,202,049
|
283.0
|
%
|
(847,371
|
)
|
-70.5
|
%
|
|||||||||
|
Total Operating Costs and Expenses
|
$
|
643,851
|
100.3
|
%
|
$
|
1,427,810
|
336.1
|
%
|
$
|
(783,959
|
)
|
-54.9
|
%
|
||||||
Operating Expenses
Our operating expenses were $190,355 in 2011 compared to $135,136 in 2010, due primarily to an increase in operating costs in Colombia. Operating expenses as a percentage of total revenues decreased to 29.7% in 2011 from 31.8% in 2010 as the increase in revenues was much greater than the increase in operating expenses.
General and Administrative Expenses
General and administrative expenses were $354,678 in 2011, a decrease of $847,371 or 70.5%, compared to $1,202,049 in 2010. Excluding the Colombian equity taxes of $860,937 as more fully described in footnote 7 above, 2010 general and administrative expenses were $341,112 in 2010, or $13,566 lower than 2011 expenses. As a percent of total revenues, general and administrative expenses decreased from 80.3%, excluding the Colombian equity taxes in 2010, to 55.3% in 2011 as revenues increased 51.1%, while general and administrative expenses only increased 4.0%.
Depreciation, depletion and accretion
Depreciation, depletion and accretion were $98,818 in 2011 and $90,625 in 2010.
11
Loss from Operations
Loss from operations was $2,107 and $1,003,047 in 2011 and 2010, respectively. Loss from operations improved by $1,000,940, due primarily to the $860,937 of equity tax recorded in 2010 compared to zero in 2011 and the increase in revenues of $216,981 in 2011 compared to 2010, offset by the $55,219 increase in operating expenses in 2011 compared to 2010.
Interest Expense
Interest expense was $55,551 in 2011 compared to $537 in 2010, an increase of $55,014. $55,000 of the increase is related to the interest on the Blackrock Promissory Note issued in January 2011.
Provision for Income Taxes
Provision for income taxes was zero in 2011 and 2010.
Net Loss
Net loss was $57,429 and $1,002,192 in 2011 and 2010, respectively. The $944,763 improvement in net loss is due primarily to the $1,000,940 improvement in loss from operations in 2011 compared to 2010, offset by the $55,014 increase in interest expense.
Foreign Currency Translation Gain/ (Loss)
Foreign currency translation gain was $6,764 in 2011 compared to a foreign currency translation loss of $15,344 in 2010. The Colombian Peso to Dollar Exchange Rate averaged 1,881 and 1,949 for the three months period ended March 31, 2011 and 2010, respectively and was 1,878 and 1,924 at March 31, 2011 and December 31, 2010.
Comprehensive Loss
Comprehensive loss was $50,665 and $1,017,536 in 2011 and 2010, respectively. Comprehensive loss improved by $966,871 due to the $944,763 improvement in net loss in 2011 compared to 2010 and the $22,108 improvement in foreign currency translation in 2011 compared to 2010.
Liquidity and Capital Resources
We had working capital deficit of $1,084,271 compared to a working capital deficit of $653,503 at December 31, 2010. Working capital at March 31, 2011 consisted primarily of $974,621 accrued expenses, $500,000 Blackrock Promissory Note due May 2011 and $134,277 of accounts payable, offset by $379,414 of cash and equivalents and $118,627 of accounts receivable. Working capital deficit at December 31, 2010 consisted primarily of $872,308 accrued expenses and $202,880 of accounts payable, offset by $307,566 of cash and equivalents and $74,678 of accounts receivable. Accounts receivable was $118,627 in 2011 and consisted primarily of a receivable from Hocol in Colombia, while accounts receivable was $74,648 in 2010 and consisted primarily of a favorable balance in the joint operating account with Pacific.
Net cash provided by operating activities totaled $22,919 in 2011 compared to net cash provided by operating activities of $48,533 in 2010. The major components of the net cash provided by operating activities in 2011 were the $98,818 provision for depreciation and depletion and the $76,787 increase in accounts payable and accrued expenses, offset by the $108,663 increase in accounts receivable and the $57,429 net loss. The major components of the net cash provided by operating activities in 2010 were the $798,709 increase in accounts payable and accrued expenses and the $144,621 decrease in accounts receivable, offset by the net loss of $1,002,192.
Net cash used by investing activities totaled $451,798 in $2011 compared to net cash used by investing activities of $9,531 in 2010. Net cash used by investing activities in 2011 consisted mostly of investments in additional Mississippian leases, while the 2010 investments were primarily related to investments in the Colombian field.
Net cash provided by financing activities totaled $500,000 in 2011 and consisted entirely of the Blackrock Promissory Note, while net cash used by financing activities totaled $983 in 2010 and consisted of payments made on the Promissory Note securing a truck.
12
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 industry. The price received for the oil produced by us fluctuated significantly during the last year. Changes in the price that we receive for our oil and gas is set by market forces beyond our control as well as governmental intervention. The volatility and uncertainty in oil and gas prices have made it more difficult for a company like us to increase our oil and gas asset base and become a significant participant in the oil and gas industry. We currently sell all of our oil and gas production to Hocol in Colombia and Sunoco in the United States. However, in the event these customers discontinued oil and gas purchases, we believe we can replace these customers with other customers who would purchase the oil at terms standard in the industry.
We have no material exposure to interest rate changes. We are subject to changes in the price of oil and exchange rates of the Colombian Peso, which are out of our control. In our Osage property, we sold oil at $84.84 in 2011 compared to prices ranging from $72.28 to $77.15 per barrel in 2010. In our Cimarrona property in Colombia, we sold oil at prices ranging from $82.21 to $105.58 in 2011 compared to $71.33 to $74.95 per barrel in 2010. The Colombian Peso to Dollar Exchange Rate averaged approximately 1,878 and 1,943 in 2011 and 2010, respectively. The Colombian Peso to Dollar Exchange Rate was approximately 1,882 and 1,923 at March 31, 2011 and March 31, 2010, respectively.
Oil and Gas Properties
We follow the "successful efforts" method of accounting for our oil and gas exploration and development activities, as set forth in the Statement of Financial Accounting Standards (SFAS) No. 19 as amended, issued by the Financial Accounting Standards Board as codified by FASC ASC topic 932 (“ASC 932”). Under this method, we initially capitalize expenditures for oil and gas property acquisitions until they are either determined to be successful (capable of commercial production) or unsuccessful. The carrying value of all undeveloped oil and gas properties is evaluated periodically and reduced if such carrying value appears to have been impaired. Leasehold costs relating to successful oil and gas properties remain capitalized while leasehold costs which have been proven unsuccessful are charged to operations in the period the leasehold costs are proven unsuccessful. Costs of carrying and retaining unproved properties are expensed as incurred.
The costs of drilling and equipping development wells are capitalized, whether the wells are successful or unsuccessful. The costs of drilling and equipping exploratory wells are capitalized until they are determined to be either successful or unsuccessful. If the wells are successful, the costs of the wells remain capitalized. If, however, the wells are unsuccessful, the capitalized costs of drilling the wells, net of any salvage value, are charged to operations in the period the wells are determined to be unsuccessful. We did not record any impairment charges in 2011 or 2010.
13
The provision for depreciation and depletion of oil and gas properties is computed on the unit-of-production method. Under this method, we compute the provision by multiplying the total unamortized costs of oil and gas properties including future development, site restoration, and dismantlement abandonment costs, but excluding costs of unproved properties by an overall rate determined by dividing the physical units of oil and gas produced during the period by the total estimated units of proved oil and gas reserves. This calculation is done on a country-by-country basis. As of March 31, 2011, our oil production operations were conducted in Colombia and in the United States of America. The cost of unevaluated properties not being amortized, to the extent there is such a cost, is assessed quarterly to determine whether the value has been impaired below the capitalized cost. The cost of any impaired property is transferred to the balance of oil and gas properties being depleted. The costs associated with unevaluated properties relate to projects which were undergoing exploration or development activities or in which we intend to commence such activities in the future. We will begin to amortize these costs when proved reserves are established or impairment is determined.
In accordance with SFAS No. 143, "Accounting for Asset Retirement Obligations," as codified by FASC ASC topic 410 (“ASC 410”), we report a liability for any legal retirement obligations on our oil and gas properties. The asset retirement obligations represent the estimated present value of the amounts expected to be incurred to plug, abandon, and remediate the producing properties at the end of their productive lives, in accordance with state laws, as well as the estimated costs associated with the reclamation of the property surrounding. The Company determines the asset retirement obligations by calculating the present value of estimated cash flows related to the liability. The asset retirement obligations are recorded as a liability at the estimated present value as of the asset's inception, with an offsetting increase to producing properties. Periodic accretion of the discount related to the estimated liability is recorded as an expense in the statement of operations.
The estimated liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells, and a risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligations. Revisions to the asset retirement obligations are recorded with an offsetting change to producing properties, resulting in prospective changes to depletion and depreciation expense and accretion of the discount. Because of the subjectivity of assumptions and the relatively long lives of most of the wells, the costs to ultimately retire the Company's wells may vary significantly from prior estimates.
Revenue Recognition
We recognize revenue upon transfer of ownership of the product to the customer which occurs when (i) the product is physically received by the customer, (ii) an invoice is generated which evidences an arrangement between the customer and us, (iii) a fixed sales price has been included in such invoice and (iv) collection from such customer is probable.
Off-Balance Sheet Arrangements
Our Company has not entered into any transaction, agreement or other contractual arrangement with an entity unconsolidated with us under which we have
|
·
|
an obligation under a guarantee contract,
|
|
·
|
a retained or contingent interest in assets transferred to the unconsolidated entity or similar arrangement that serves as credit, liquidity or market risk support to such entity for such assets,
|
|
·
|
any obligation, including a contingent obligation, under a contract that would be accounted for as a derivative instrument, or
|
|
·
|
any obligation, including a contingent obligation, arising out of a variable interest in an unconsolidated entity that is held by us and material to us where such entity provides financing, liquidity, market risk or credit risk support to, or engages in leasing, hedging or research and development services with us.
|
Our company is a Smaller Reporting Company. A Smaller Reporting Company is not required to provide the disclosure information required by this item.
14
The Company’s management, including the Company’s principal executive officer and principal financial officer, evaluated the effectiveness of the Company’s “disclosure controls and procedures,” as such term is defined in Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended, (the “Exchange Act”). Based upon their evaluation, the principal executive officer and principal financial offer concluded that, as of the end of the period covered by this report, the Company’s disclosure controls and procedures were not effective for the purpose of ensuring that the information required to be disclosed in the reports that the Company files or submits under the Exchange Act with the Securities and Exchange Commission (the “SEC”) (1) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (2) is accumulated and communicated to the Company’s management, including its principal executive and principal financial offers, as appropriate to allow timely decisions regarding required disclosure.
Management conducted an assessment of the effectiveness of the Company’s internal control over financial reporting as of March 31, 2011, utilizing a top-down, risk based approach described in SEC Release No. 34-55929 as suitable for smaller public companies. Based on this assessment, management determined that the Company’s internal control over financial reporting as of March 31, 2011 is not effective. Based on this assessment, management has determined that, as of March 31, 2011, there were material weaknesses in our internal control over financial reporting. The material weaknesses identified during management's assessment was the lack of independent oversight by an audit committee of independent members of the Board of Directors. As defined by the Public Company Accounting Oversight Board Auditing Standard No. 5, a material weakness is a deficiency or a combination of deficiencies, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected. Given the difficulty of finding qualified individuals who are willing to serve as independent directors, there has been no change in the audit committee.
Our internal control over financial reporting includes policies and procedures that pertain to the maintenance of records that accurately and fairly reflect, in reasonable detail, transactions and dispositions of assets; and provide reasonable assurances that: (1) transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States; (2) receipts and expenditures are being made only in accordance with authorizations of management and the directors of the Company; and (3) unauthorized acquisitions, use, or disposition of the Company’s assets that could have a material affect on the Company’s financial statements are prevented or timely detected.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparations and presentations. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
This quarterly report does not include an attestation report of the Company’s independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s independent registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this quarterly report.
Except as indicated herein, there were no changes in the Company’s internal control over financial reporting during the three months ended March 31, 2011 that have materially affected, or are reasonable likely to materially affect, the Company’s internal control over financial reporting.
15
We are not a party to, or the subject of, any material pending legal proceedings other than ordinary, routine litigation incidental to our business.
Our company is a Smaller Reporting Company. A Smaller Reporting Company is not required to provide the risk factor disclosure required by this item.
|
(a)
|
None
|
(b) None
(c) None
None
None
(a) None
(b) None
See Exhibit Index attached hereto.
16
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 12, 2011
|
By:
|
/s/ Kim Bradford | |
| Kim Bradford | |||
|
President and Chief Executive Officer
|
|||
|
Date: May 12, 2011
|
By:
|
/s/ Kim Bradford | |
| Kim Bradford | |||
|
Principal Financial Officer
|
17
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).
|
|
(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
|
18