10-K 1 form10k.htm ANNUAL REPORT Form 10-K

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

[X] Annual Report Pursuant to Section 13 or 15(d) of The Securities Exchange Act of 1934

For the Fiscal Year Ended December 31, 2011

[  ] Transition Report Pursuant to Section 13 or 15(d) of The Securities Exchange Act of 1934

 

Commission File Number: 0-52718

 

OSAGE EXPLORATION & DEVELOPMENT, INC.

(Exact name of registrant as specified in its charter)

 

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

 

2445 Fifth Avenue, Suite 310, San Diego, California 92101

(Address of principal executive offices) (Zip Code)

 

Registrant’s telephone no.:  (619) 677-3956

 

Securities registered pursuant to Section 12(b) of the Exchange Act:   None

 

Securities registered pursuant to Section 12(g) of the Exchange Act:   Common stock, par value $0.0001

 

Indicate by check mark is the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes [  ] No [X]

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes [  ] No [X]

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Security Exchange Act of 1934 during the preceding 12 months (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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K of any amendment to this Form 10-K. [X]

 

Indicate by check mark whether registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “accelerated filer,” “large accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):  

 

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 Rule 12b-2 of the Act). Yes [  ] No [X]

 

The aggregate market value of the issuer’s Common stock held by non-affiliates of the registrant on March 16, 2012 was approximately $21,625,656 based on the closing price of $0.87 as reported on the NASD’s OTC Electronic Bulletin Board system.

 

As of March 21, 2012, there were 47,974,775 shares of Osage Exploration and Development, Inc., Common stock, par value $0.0001, outstanding.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

A description of “Documents Incorporated by Reference” is contained in Part III, Item 13.

Transitional Small Business Disclosure Format. Yes[  ] No [X]

 

 

 

 
 

 

TABLE OF CONTENTS

 

    Page
PART I
     
Item 1. Business 3
     
Item 1A. Risk Factors 6
     
Item 1B. Unresolved Staff Comments 9
     
Item 2. Properties 9
     
Item 3. Legal Proceedings 12
     
Item 4. Removed and Reserved 12
     
PART II
     
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 12
     
Item 6. Selected Financial Data 13
     
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 13
     
Item 7A. Quantitative and Qualitative Disclosures About Market Risk 19
     
Item 8. Financial Statements and Supplementary Data 20
     
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure 21
     
Item 9A. Controls and Procedures 21
     
Item 9B. Other Information 22
     
PART III
     
Item 10. Directors, Executive Officers and Corporate Governance 22
     
Item 11. Executive Compensation 24
     
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 26
     
Item 13. Certain Relationships and Related Transactions, and Director Independence 27
     
Item 14. Principal Accounting Fees and Services 28
     
PART IV
     
Item 15. Exhibits, Financial Statement Schedules 29
     
Signatures. 31
     
Financial Statements and Financial Statement Schedules F-1

 

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Cautionary Statement

 

IN ADDITION TO HISTORICAL INFORMATION, THIS ANNUAL REPORT CONTAINS FORWARD-LOOKING STATEMENTS WITHIN THE MEANING OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995 AND THE COMPANY DESIRES TO TAKE ADVANTAGE OF THE “SAFE HARBOR” PROVISIONS THEREOF. THEREFORE, THE COMPANY IS INCLUDING THIS STATEMENT FOR THE EXPRESS PURPOSE OF AVAILING ITSELF OF THE PROTECTIONS OF SUCH SAFE HARBOR WITH RESPECT TO ALL OF SUCH FORWARD-LOOKING STATEMENTS. THE FORWARD-LOOKING STATEMENTS IN THIS REPORT REFLECT THE COMPANY’S CURRENT VIEWS WITH RESPECT TO FUTURE EVENTS AND FINANCIAL PERFORMANCE. THESE FORWARD-LOOKING STATEMENTS ARE SUBJECT TO CERTAIN RISKS AND UNCERTAINTIES, INCLUDING THOSE DISCUSSED HEREIN, THAT COULD CAUSE ACTUAL RESULTS TO DIFFER MATERIALLY FROM HISTORICAL RESULTS OR THOSE ANTICIPATED. IN THIS REPORT, THE WORDS “ANTICIPATES,” “BELIEVES,” “EXPECTS,” “INTENDS,” “FUTURE” AND SIMILAR EXPRESSIONS IDENTIFY FORWARD-LOOKING STATEMENTS. READERS ARE CAUTIONED TO CONSIDER THE SPECIFIC RISK FACTORS DESCRIBED BELOW AND NOT TO PLACE UNDUE RELIANCE ON THE FORWARD-LOOKING STATEMENTS CONTAINED HEREIN, WHICH SPEAK ONLY AS OF THE DATE HEREOF. THE COMPANY UNDERTAKES NO OBLIGATION TO PUBLICLY REVISE THESE FORWARD-LOOKING STATEMENTS TO REFLECT EVENTS OR CIRCUMSTANCES THAT MAY ARISE AFTER THE DATE HEREOF.

 

Item 1. Business

 

Overview

 

Osage Exploration and Development, Inc., (“Osage” or the “Company”) is an oil and natural gas exploration and production company with proved reserves and existing production in the country of Colombia and the state of Oklahoma. We are headquartered in San Diego, California with field offices in Oklahoma City, Oklahoma and Bogota, Colombia.

 

Our operations in Colombia accounted for approximately 98% and 95% of our total revenues in 2011 and 2010, respectively.

 

Mississippian

 

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 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.

 

Cimarrona

 

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 (“Cimarrona LLC”), an Oklahoma limited liability company. 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 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 April 1, 2008.

 

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The purchase price consisted of 2,750,000 shares of our common stock and a warrant to purchase 1,125,000 shares of common stock at $1.25 per share, expiring April 8, 2013. In addition, we issued 50,000 shares of common stock to a financial advisor and $22,500 as a finder’s fee. The total purchase price for the Cimarrona acquisition was $2,090,345.

 

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 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 indicates the partners in the Association Contract 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 reduce the cash flows generated by the property 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 Rubiales Energy Corp. (“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 2011 and 2010, Pacific reimbursed us $ 0 and $154,289, respectively for capital expenditures related to certain disputes regarding the pipeline. These amounts were originally included as capitalized costs of the pipeline. No gain or loss was recognized from these transactions.

 

Osage, Oklahoma

 

In 2005, we purchased, for $103,177, 100% of the working interest and became the operator in certain producing oil and natural gas leases located in Osage County, Oklahoma (the “Hopper Property”), which property consists of 23 wells, 10 of which are producing, on 480 acres.

 

Background

 

We were organized September 9, 2004 as Osage Energy Company, 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 that survived the merger. The merger was consummated through the issuance of 10,000,000 shares of our common stock. The financial records of the Company prior to merger are those of Osage Energy Company, LLC.

 

The Nevada 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. On April 24, 2006, Kachina Gold Corporation merged with Osage Energy Company, LLC. and on May 15, 2006 changed its name to Osage Energy Corporation. On July 2, 2007, the domicile of the Company was changed to Delaware and in connection therewith, the name of the Company was changed to Osage Exploration and Development, Inc. On February 27, 2008, our stock began trading on the NASDAQ OTC Bulletin Board market under the ticker “OEDV.OB”

 

Our principal office is located at 2445 Fifth Avenue, Suite 310 San Diego, California 92101. Our phone number is (619) 677-3956.

 

Distribution Methods

 

We currently generate oil sales from our production operations in Colombia and in the state of Oklahoma and pipeline revenues from our Cimarrona property in Colombia. Historically, all of the oil produced on our Hopper Property in Osage County, Oklahoma was sold to Sunoco, Inc. (“Sunoco”). However, starting in September 2011, all of the oil produced in the Hopper Property is sold to Coffeyville Resources Refining & Marketing, LLC (“Coffeyville”). Coffeyville picks up oil from our tanks and pays us according to market prices at the time of pick up. There is significant demand for oil and there are several companies in our area that purchase oil from small oil producers.

 

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In Colombia, we sell oil from the Guaduas field, where we sell all of our oil production to Hocol, S.A. (“Hocol”). We believe that if Hocol discontinued oil purchases, we will be able to replace it with other customers which would purchase the oil at terms standard in the industry. All of our pipeline revenues are generated from sales volumes attributable to Pacific, the operator of the Cimarrona property. For 2011, Hocol, Pacific, Coffeyville and Sunoco accounted for 53.1%, 45.4%, 0.9% and 0.6%, respectively, of total revenues. For 2010, Hocol, Pacific and Sunoco accounted for 74.7%, 19.9% and 5.4%, respectively, of total revenues.

 

We presently have no sales of natural gas. Should we decide to sell our production of natural gas, we will seek to enter into distribution agreements that would provide for us to tap into the distribution line of a gas distribution company, and we would be paid for our gas at the market price at the time of delivery less any transportation charge from the gas transmission company. These charges can range widely from 5% to 30% or more of the market value of the gas depending on the availability of competition and other factors.

 

Research and Development

 

We have not allocated funds to conducting research and development activities, nor do we anticipate allocating funds to research and development in the future.

 

Patents, Trademarks, Royalties, Etc.

 

We have no patents, trademarks, licenses, concessions, or labor contracts.

 

In our Hopper Property in Oklahoma, we pay royalties of 18.75% of oil and gas sales, net of taxes, to the Osage Nation. If our production increases to more than 100 barrels of oil per producing well per day, the royalty will increase to 20.0%. The leases do not expire, and royalties are owed as long as there is production on the property.

 

Royalty rates range from 12.5% to 25.0% on our leases in Logan, Coal and Pawnee counties in Oklahoma. Most of our leases require us to drill a well on the lease within three years of entering into a lease. If we do not drill during that time and do not have an option to extend the lease, we will lose that lease.

 

In Colombia, pursuant to the Association Contract with Ecopetrol, we pay royalties of 20.0% of oil produced to Ecopetrol.

 

Government Approvals

 

We are required to get approval from the Oklahoma Corporation Commission and Colombian governmental agencies before any work can begin on any well in Oklahoma and Colombia, respectively, and before production can be sold. We have all of the required permits on the properties currently in operation.

 

Existing or Probable Governmental Regulations

 

We, currently, are active in the country of Colombia and the state of Oklahoma. The development and operation of oil and gas properties is highly regulated by states and/or foreign governments. In some areas of exploration and production, the United States government or a foreign governmental agency regulates the industry.

 

Regulations, whether state or federal or international, control numerous aspects of drilling and operating oil and gas wells, including the care of the environment, the safety of the workers and the public, and the relations with the owners and occupiers of the surface lands within or near the leasehold acreage. The effect of these regulations, whether state or federal or international, is invariably to increase the cost of operations.

 

The costs of complying with state regulations include a permit for drilling a well before beginning a project. Other compliance matters have to do with keeping the property free of oil spills and the plugging of wells when they no longer produce. If oil spills are not cleaned up on a timely basis fines can range from a few dollars to as high as several thousand dollars. We utilize consultants and independent contractors to visit and monitor our properties in Oklahoma on a regular basis to prevent mishaps and ensure prompt attention and, if necessary, appropriate correction and remedial activity. The other significant cost of compliance with state regulations is the plugging of wells after their useful life. In most instances, there is pumping equipment and pipe which can be salvaged to offset some if not all of that cost. Plugging a well consists of pumping cement into the well bore sufficient to prevent any oil and gas zone from ever leaking and contaminating the fresh water supply.

 

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Costs and Effects of Compliance with Environmental Laws

 

There is a cost in complying with environmental laws that is associated with each well that is drilled or operated, which cost is added to the cost of the operation. Each well will have an additional cost associated with plugging and abandoning the well when it is no longer commercially viable. The estimated costs of dismantlement and abandonment of depleted wells on our Hopper Property in Osage County, Oklahoma and our Rosablanca Property are estimated to be $92,000 and $35,719, respectively. As of December 31, 2011, we have not incurred any dismantlement and abandonment costs. However, we believe that the salvage value of the equipment on the wells will be sufficient in amount to offset some of such costs.

 

Employees

 

We currently have two full-time executive employees: Kim Bradford, President, Chief Executive Officer and Chief Financial Officer and Greg Franklin, Chief Geologist. We utilize third parties to provide certain operational, technical, accounting, finance and administrative services. As production levels increase, we may need to hire additional personnel or expand the use of third parties.

 

Facilities

 

We lease 1,386 square feet of modern office space in San Diego, California as our corporate headquarters pursuant to a 36 month lease from February 2011. We paid $3,188 per month for the first 12 months, increasing 3.5% in years 2 and 3. In addition, we are responsible for any increases in building operating expenses beyond 2008 base year operating expenses.

 

We lease approximately 1,000 square feet of modern office space in Oklahoma City, Oklahoma consisting of a large conference room, three offices, a drafting room and a storage room. The lease is based on a verbal agreement with a third party on a month-to-month basis for $1,100.

 

Available Information

 

Our Internet website address is www.osageexploration.com. Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports filed or furnished pursuant to section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) are available free of charge through our Company’s website as soon as reasonably practicable after those reports are electronically filed with, or furnished to, the Securities and Exchange Commission (the “SEC”).

 

Item 1A. Risk Factors

 

Cautionary Note on Forward Looking Statements

 

In addition to the other information in this annual report the factors listed below should be considered in evaluating our business and prospects. This annual report contains a number of forward-looking statements that reflect our current views with respect to future events and financial performance. These forward-looking statements are subject to certain risks and uncertainties, including those discussed below and elsewhere herein, that could cause actual results to differ materially from historical results or those anticipated. In this report, the words “anticipates,” “believes,” “expects,” “intends,” “future” and similar expressions identify forward-looking statements. Readers are cautioned to consider the specific factors described below and not to place undue reliance on the forward-looking statements contained herein, which speak only as of the date hereof. We undertake no obligation to publicly revise these forward-looking statements, to reflect events or circumstances that may arise after the date hereof.

 

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Risks Relating to Our Business

 

We have a history of losses and may incur future losses.

 

We have incurred significant operating losses in prior years and at December 31, 2011 had an accumulated deficit of $7,558,080. We had an operating loss of $386,403 and $1,622,464 in 2011 and 2010, respectively. In 2011, we recognized a one-time gain of $3,109,646 on assignment of our interest in certain leases in Logan County, Oklahoma. Given the level of operating expenditures and the uncertainty of revenues and margins, we may continue to incur losses and negative cash flows in future periods. The failure to obtain sufficient revenues and margins to support operating expenses could harm our business.

 

We have limited operating capital.

 

To continue growth and to fund our expansion plans, we will require additional financing. The amount of capital available to us is limited, and may not be sufficient to enable us to fully execute our growth plans without additional fund raising. Additional financing may be required to meet our objectives and provide more working capital for expanding our development and marketing capabilities and to achieve our ultimate plan of expansion and full scale of operations. There is no assurance we will be able to obtain such financing on attractive terms, if at all.

 

We do not intend to pay dividends to our stockholders.

 

We do not currently intend to pay cash dividends on our common stock and do not anticipate paying any dividends at any time in the foreseeable future. At present, we will follow a policy of retaining all of our earnings, if any, to finance development and expansion of our business.

 

Our officers and directors have limited liability, and we are required in certain instances to indemnify our officers and directors for breaches of their fiduciary duties.

 

We have adopted provisions in our Certificate of Incorporation and Bylaws which limit the liability of our officers and directors and provide for indemnification by us of our officers and directors to the full extent permitted by Delaware corporate law. Our Certificate of Incorporation generally provides that our officers and directors shall have no personal liability to us or our stockholders for monetary damages for breaches of their fiduciary duties as directors, except for breaches of their duties of loyalty, acts or omissions not in good faith or which involve intentional misconduct or knowing violation of law, acts involving unlawful payment of dividends or unlawful stock purchases or redemptions, or any transaction from which a director derives an improper personal benefit. Such provisions substantially limit our stockholders’ ability to hold officers and directors liable for breaches of fiduciary duty, and may require us to indemnify our officers and directors.

 

We face great competition.

 

We compete against many other energy companies, some of which have considerably greater resources and abilities. These competitors may have greater marketing and sales capacity, established distribution networks, significant goodwill and global name recognition.

 

Our success depends to a significant degree upon the involvement of our management, who are in charge of our strategic planning and operations. We may need to attract and retain additional talented individuals in order to carry out our business objectives. The competition for such persons could be intense and there are no assurances that these individuals will be available to us.

 

Our business is subject to extensive regulation.

 

Many of our activities are subject to Colombian, federal, state and/or local regulation, and as these rules are subject to constant change or amendment, there can be no assurance that our operations will not be adversely affected by new or different government regulations, laws or court decisions applicable to our operations.

 

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Government regulation and liability for environmental matters may adversely affect our business and results of operations.

 

Crude oil and natural gas operations are subject to extensive international, federal, state and local government regulations, which may be changed from time to time. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of crude oil and natural gas wells below actual production capacity in order to conserve supplies of crude oil and natural gas. There are international, federal, state and local laws and regulations primarily relating to protection of human health and the environment applicable to the development, production, handling, storage, transportation and disposal of crude oil and natural gas, byproducts thereof and other substances and materials produced or used in connection with crude oil and natural gas operations. In addition, we may inherit liability for environmental damages caused by previous owners of property we purchase or lease. As a result, we may incur substantial liabilities to third parties or governmental entities. We are also subject to changing and extensive tax laws, the effects of which cannot be predicted. The implementation of new, or the modification of existing, laws or regulations could have a material adverse effect on us.

 

The reserves we report in our SEC filings are estimates and may prove to be inaccurate.

 

There are numerous uncertainties inherent in estimating crude oil and natural gas reserves and their estimated values. The reserves we report in our filings with the SEC are only estimates and may prove to be inaccurate because of these uncertainties. Reservoir engineering is a subjective and inexact process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner. Estimates of economically recoverable crude oil and natural gas reserves depend upon a number of variable factors, such as historical production from the area compared with production from other producing areas and assumptions concerning effects of regulations by governmental agencies, future crude oil and natural gas prices, future operating costs, severance and excise taxes, development costs and work-over and remedial costs. Some or all of these assumptions may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of crude oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected there from prepared by different engineers or by the same engineers but at different times may vary substantially. Accordingly, reserve estimates may be subject to downward or upward adjustment. Actual production, revenue and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material.

 

Crude oil prices are highly volatile in general and low prices will negatively affect our financial results.

 

Our revenues, operating results, profitability, cash flow, future rate of growth and ability to borrow funds or obtain additional capital are substantially dependent upon prevailing prices of crude oil. Lower crude oil and natural gas prices also may reduce the amount of crude oil and natural gas that we can produce economically. Historically, the markets for crude oil and natural gas have been very volatile, and such markets are likely to continue to be volatile in the future. Prices for crude oil and natural gas are subject to wide fluctuation in response to relatively minor changes in the supply of and demand for crude oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control, including: worldwide and domestic supplies of crude oil and natural gas; the level of consumer product demand; weather conditions; domestic and foreign governmental regulations; the price and availability of alternative fuels; political instability or armed conflict in oil producing regions; the price and level of foreign imports; and overall domestic and global economic conditions.

 

At our Hopper Property, in Osage County, Oklahoma, we sold oil at $82.73 to $96.89 per barrel in 2011 compared to $68.61 to $85.25 per barrel in 2010. In our Cimarrona property in Colombia, we sold oil at $82.21 to $120.22 per barrel in 2011 compared to $63.32 to $81.04 per barrel in 2010.

 

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Risks Relating to Trading in Our Common stock

 

The market price for our common stock may be volatile, and you may not be able to sell our stock at a favorable price or at all.

 

Many factors could cause the market price of our common stock to rise and fall, including: actual or anticipated variations in our quarterly results of operations; changes in market valuations of companies in our industry; changes in expectations of future financial performance; fluctuations in stock market prices and volumes; issuances of dilutive common stock or other securities in the future; the addition or departure of key personnel; and the increase or decline in the price of oil and natural gas. It is possible that the proceeds from sales of our common stock may not equal or exceed the prices you paid for it plus the costs and fees of making the sales.

 

Substantial sales of our common stock, or the perception that such sales might occur, could depress the market price of our common stock.

 

We cannot predict whether future issuances of our common stock or resales in the open market by current stockholders will decrease the market price of our common stock. The impact of any such issuances or resales of our common stock on our market price may be increased as a result of the fact that our common stock is thinly, or infrequently, traded. The exercise of any options, warrants or the vesting of any restricted stock that we may grant to directors, officers, employees and consultants in the future, the issuance of common stock in connection with acquisitions and other issuances of our common stock could have an adverse effect on the market price of our common stock. In addition, future issuances of our common stock may be dilutive to existing stockholders. Any sales of substantial amounts of our common stock in the public market, or the perception that such sales might occur, could lower the market price of our common stock.

 

Our common stock is considered to be a “penny stock” security under the Exchange Act rules, which may limit the marketability of our securities.

 

Our securities are considered low-priced or “designated" securities under rules promulgated under the Exchange Act. Under these rules, broker/dealers participating in transactions in low-priced securities must first deliver a risk disclosure document which describes the risks associated with such stocks, the broker/dealers’ duties, the customer’s rights and remedies, certain market and other information, and make a suitability determination approving the customer for low-priced stock transactions based on the customer’s financial situation, investment experience and objectives. Broker/dealers must also disclose these restrictions in writing to the customer and obtain specific written consent of the customer, and provide monthly account statements to the customer. The likely effect of these restrictions is a decrease in the willingness of broker/dealers to make a market in the stock, decreased liquidity of the stock and increased transaction costs for sales and purchases of the stock as compared to other securities.

 

Item 1B. Unresolved Staff Comments

 

None

 

Item 2 .Properties

 

The principal assets of the Company consist of proved and unproved oil and gas properties, a pipeline and oil and gas production related equipment. Our oil and gas properties are located in the country of Colombia and in the state of Oklahoma. Our pipeline is located in Colombia.

 

Developed oil and gas properties are those on which sufficient wells have been drilled to economically recover the estimated reserves calculated for the property. Undeveloped properties do not presently have sufficient wells to recover the estimated reserves.

 

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There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the Company and the operators. The reserve data set forth in Supplemental Information to Consolidated Financial Statements represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of crude oil and condensate, natural gas liquids and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the amount and quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers normally vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimate upward or downward. Accordingly, reserve estimates are often different from the quantities ultimately recovered. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they were based.

 

Management maintains internal controls designed to provide reasonable assurance that the estimates of proved reserves are computed and reported in accordance with rules and regulations as promulgated by the SEC. The Company retained Reddy Petroleum Company (“Reddy”) to prepare estimates of our oil and gas reserves in our Hopper Property in Osage County, Oklahoma. Management is responsible for providing the following information related to our oil and gas properties to the firm: working and net revenue interests, historical production rates, current operating and future development costs, and geoscience, engineering and other information. Greg Franklin, our Chief Geologist, reviews the final reserve estimate for completeness and reasonableness and, if necessary, discusses the process used and findings with the designated technical person at Reddy. Our Chief Geologist has over 25 years of oil and gas experience and is a registered professional engineer. The technical person primarily responsible for audit of our reserve estimates at Reddy meets the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Reddy is an independent firm of petroleum engineers, geologists, geophysicists, and petro physicists; they do not own an interest in our properties and are not employed on a contingent fee basis. Reserve estimates are imprecise and subjective and may change at any time as additional information becomes available. Furthermore, estimates of oil and gas reserves are projections based on engineering data. There are uncertainties inherent in the interpretation of this data as well as the projection of future rates of production. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.

 

Pacific, the operator and owner of 90.6% of the Guaduas field in Columbia, retained Petrotech Engineering Ltd. (“Petrotech”) to prepare estimates of oil and gas reserves in the Cimarrona property. Management of Pacific provided information relating to working and net revenue interests, historical production rates, current operating and future development costs, and geoscience, engineering and other information. Management of Pacific reviews the final reserve estimate for completeness and reasonableness and, if necessary, discusses the process used and findings with the designated technical person at Petrotech. The report provided by Petrotech is for Pacific’s 90.6% ownership of the field.

 

The Company’s estimated future net recoverable oil and gas reserves from proved reserves, both developed and undeveloped properties, were assembled by independent petroleum engineers, Petrotech for the Cimarrona property in Colombia as of December 31, 2011 and 2010, and Reddy for the Hopper Property in Osage County, Oklahoma as of December 31, 2011 and 2010, respectively, and are as follows:

 

   Crude Oil (BBLs)   Natural Gas (MCF) 
   Colombia   United States   Total   Colombia   United States   Total 
December 31, 2011   124,362    113,193    237,555    364,587    200,980    565,567 
December 31, 2010   272,600    126,443    399,043    58,620    200,771    259,391 

 

Using year-end oil and gas prices and lease operating expenses, the estimated value of future net revenues to be derived from the Company’s proved developed oil and gas reserves, discounted at 10%, were approximately $6.48 million and $9.67 million for our 9.4% share of Cimarrona Property at December 31, 2011 and 2010, respectively and $5.35 million and $6.18 million for the Hopper Property in Osage County, Oklahoma, at December 31, 2011 and 2010, respectively.

 

10
 

  

The Company’s net oil production after royalty and other working interests for 2011 and 2010 were as follows:

 

   Crude Oil (BBLs) 
    Colombia    United States    Total 
December 31, 2011   18,365    797    19,162 
December 31, 2010   17,607    1,761    19,368 

 

The Company’s average production cost per barrel is as follows:

 

   2011   2010 
   USA   Colombia   Total   USA   Colombia   Total 
Average Production Cost per Barrel  $124.51   $32.90   $35.97   $52.34   $20.40   $22.77 

 

The following summarizes the developed leasehold acreage held by the Company as of December 31, 2011 and 2010. Gross acres are the total number of acres in which the Company has a working interest. Net acres are the sum of the Company’s fractional interests owned in the gross acres. Developed acreage is acreage in which we have leased the mineral rights for oil and gas and have drilled or re-worked wells. Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.

 

   Developed Acreage   Developed Acreage 
   Gross Acreage   Net Acreage 
   Colombia   United States   Combined   Colombia   United States   Combined 
December 31, 2011   136,265    480    136,745    12,809    480    13,289 
December 31, 2010   136,265    480    136,745    12,809    480    13,289 

 

   Undeveloped   Undeveloped 
   Gross Acreage   Net Acreage 
   Colombia   United States   Combined   Colombia   United States   Combined 
December 31, 2011   -    40,524    40,524    -    8,613    8,613 
December 31, 2010   -    8,136    8,136    -    5,364    5,364 

 

The following summarizes the Company’s productive oil wells as of December 31, 2011 and 2010. Productive wells are producing wells and wells capable of production. Gross wells are the total number of wells in which the Company has an interest. Net wells are the sum of the Company’s fractional interests owned in the gross wells.

 

   Productive Wells   Productive Wells 
   Gross Wells   Net Wells 
   Colombia   United States   Combined   Colombia   United States   Combined 
December 31, 2011   7.0    10.0    17.0    0.7    10.0    10.7 
December 31, 2010   7.0    10.0    17.0    0.7    10.0    10.7 

 

Drilling Activity

 

In 2011, we drilled two salt water disposal wells and commenced drilling the Wolfe#1-29H, our first horizontal Mississippian well in Logan County, Oklahoma. In January 2012, we began drilling the Krittenbrink 2-36H, our second well in Logan County. In 2010, we did not drill any wells.

 

Delivery Commitments

 

We are not obligated to provide a fixed and determinable quantity of oil or natural gas in the near future under existing contracts or agreements. Further, during the last three years we had no significant delivery commitments.

 

11
 

  

Item 3. Legal Proceedings

 

Neither our Company nor any of its property is a party to, or the subject of, any material pending legal proceedings other than ordinary, routine litigation incidental to our business.

 

Item 4. (Removed and Reserved)

 

Not applicable.

 

PART II

 

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

 

Our common stock trades on the OTC Bulletin Board under the symbol “OEDV.OB”. The high and low closing prices, as reported by the OTC Bulletin Board, are as follows for 2011 and 2010. The quotations reflect inter-dealer prices, without retail mark-up, mark-down or commission and may not represent actual transactions.

 

   High   Low 
Year ended December 31, 2011           
First Quarter  $0.15   $0.03 
Second Quarter  $0.33   $0.13 
Third Quarter  $0.62   $0.28 
Fourth Quarter  $0.52   $0.27 
           
Year ended December 31, 2010          
First Quarter  $0.07   $0.03 
Second Quarter  $0.07   $0.03 
Third Quarter  $0.05   $0.03 
Fourth Quarter  $0.05   $0.02 

 

Dividends

 

We have declared no cash dividends on our common stock since inception. There are no restrictions that limit our ability to pay dividends on our common stock or that are likely to do so in the future other than the restrictions set forth in Section 170(b) of the Delaware General Corporation Law that provides that a company may declare and pay dividends upon the shares of its capital stock either (1) out of its surplus, as defined in and computed in accordance with Sections 154 and 244 of the Delaware General Corporation Law, or (2) in case there shall be no such surplus, out of its net profits for the fiscal year in which the dividend is declared and/or the preceding fiscal year. We have not declared, paid cash dividends, or made distributions in the past. We do not anticipate that we will pay cash dividends or make distributions in the foreseeable future. We currently intend to retain and reinvest future earnings to finance operations.

 

Securities Authorized for Issuance Under Equity Compensation Plans

 

In June 2007, we implemented the 2007 Osage Exploration and Development, Inc. Equity-Based Compensation Plan (the “Plan”) which allows the reservation of 5,000,000 shares under the Plan. Under this Plan, securities issued may include options, stock appreciation rights (“SARs”) and restricted stock. No securities have yet been issued under this plan since inception.

 

12
 

  

Holders

 

As of March 15, 2012, there were approximately 300 holders of record of our common stock, which figure does not take into account those stockholders whose certificates are held in the name of broker-dealers or other nominee accounts.

 

Issuer Purchase of Equity Securities

 

None.

 

Item 6. Selected Financial Data

 

Not Applicable.

 

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation.

 

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 the Purchase Agreement with Sunstone pursuant to which we acquired from Sunstone 100% of the membership interests in 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 in excess of 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 the Association Contract whereby we pay Ecopetrol royalties of 20% of the oil produced. The royalty 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 indicates the partners in the Association Contract 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 reduce the cash flows generated by the property 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.

 

13
 

  

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 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.

 

On April 21, 2011, we entered into a participation agreement (the “Participation Agreement”) with Slawson Exploration Company (“Slawson”) and U.S. Energy Development Corporation (“USE”). Pursuant to the terms of the Participation Agreement, Slawson and USE acquired 45% and 30% respectively, of our 10,000 acre Nemaha Ridge prospect in Logan County, OK 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. Since the Participation Agreement was signed, Slawson and USE acquired 45% and 30%, respectively, of an additional 11,844 acres that we offered to them. At December 31, 2011, we had 5,181 net acres (20,723 gross) leased in Logan County. In December 2011, we began drilling the Wolfe 1-29H, our first well in Logan County and in January 2012, we began drilling the Krittenbrink 2-36H, our second well in Logan County.

 

In July 2011, we entered into an agreement with B&W Exploration, Inc. (“B&W”) whereby we purchased from 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. At December 31, 2011, we had 915 net acres (1,624 gross) leased in Pawnee County.

 

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. The Woodford shale rock is silica-rich, is very brittle and generates lots of natural fractures. At December 31, 2011, we had 2,517 net (6,473 gross) acres leased in Coal County.

 

At December 31, 2011, we have leased 40,524 gross (8,613 net) acres across three counties in Oklahoma as follows:

 

   Gross   Net 
Logan   32,427    5,181 
Pawnee   1,624    915 
Coal   6,473    2,517 
Total   40,524    8,613 

 

The Company has an accumulated deficit of $7,558,080 at December 31, 2011 and $10,093,679 at December 31, 2010. The Company recognized a one-time gain of $3,109,646 from assignment of leases in Logan County, OK. Excluding this gain, the Company would have recorded a net loss for 2011. 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.

 

14
 

  

We anticipate we will need to raise at least $10,000,000 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) controlling overhead and operating and (c) raising additional capital and/or obtaining financing.

 

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

 

Year ended December 31, 2011 compared to year ended December 31, 2010

 

   2011   2010   Increase/(Decrease) 
   Amount   Percentage   Amount   Percentage   Amount   Percentage 
                         
Oil Sales  $1,920,834    54.6%  $1,468,070    80.1%  $452,764    30.8%
Pipeline Sales   1,594,889    45.4%   365,707    19.9%   1,229,182    336.1%
Total Revenues  $3,515,723    100.0%  $1,833,777    100.0%  $1,681,946    91.7%

 

Oil Sales

 

Oil sales were $1,920,834 in 2011, an increase of $452,764, or 30.8% in 2011, compared to $1,468,070 in 2010. The increase in oil sales is mostly due to an increase in the average price per barrel sold. In Colombia, we sold 19,000 barrels (“BBLs”) in both 2011 and 2010. However, in 2011, we sold oil at an average price per barrel of $101.86 compared to $74.71 in 2010. In the United States, all of our sales came from the Hopper Property in Osage County. We sold 797 BBL in 2011 at an average price of $88.60 per barrel, compared to 1,761 BBLs in 2010 at an average price of $74.02 per barrel.

 

Pipeline Sales

 

Pipeline sales were $1,594,889 in 2011, an increase of $1,229,182, or 336.1%, compared to $365,707 in 2010. In 2011, the pipeline transported 9.17 million BBls (our share was approximately 0.86 million BBLs) compared to 2.26 million BBls (our share was approximately 0.21 million BBLs) in 2010.

 

Total Revenues

 

Total revenues were $3,515,723, an increase of $1,681,946, or 91.7%, in 2011 compared to $1,833,777 in 2010. Approximately 99% and 95% of our 2011 and 2010 revenues, respectively, were derived from our Cimarrona property in Colombia. Oil sales accounted for approximately 54.6% and 80.1% of total revenues in 2011 and 2010, respectively.

 

15
 

  

Production

 

   2011   2010   Increase/(Decrease) 
   Net Barrels   % of Total   Net Barrels   % of Total   Barrels   % 
Colombia   18,365    95.8%   17,607    90.9%   758    4.3%
United States   797    4.2%   1,761    9.1%   (964)   -54.7%
Total   19,162    100.0%   19,368    100.0%   (206)   -1.1%

 

Production, net of royalties, was 19,162 BBLs, a decrease of 206 BBLs, or 1.1% in 2011 compared to 19,368 BBLs in 2010. Colombian production, net of royalties, accounted for 95.8% and 90.9% of total production in 2011 and 2010, respectively.

 

Operating Costs and Expenses

 

   2011   2010   Increase/(Decrease) 
       Percent of       Percent of         
   Amount   Revenues   Amount   Revenues   Amount   Percentage 
Operating Expenses                              
Well Operating  $1,068,087    30.4%  $646,240    35.2%  $421,847    65.3%
General & Administrative   1,686,686    48.0%   1,389,539    75.8%  $297,147    21.4%
Equity Tax   450,064    12.8%   1,029,699    56.2%  $(579,635)   -56.3%
Depreciation , Depletion and Accretion   429,689    12.2%   351,463    19.2%  $78,226    22.3%
Stock Based Compensation Expense   267,600    7.6%   39,300    2.1%  $228,300    580.9%
Total Operating Costs and Expenses  $3,902,126    111.0%  $3,456,241    188.5%  $445,885    12.9%

 

Well Operating Expenses

 

Our well operating expenses in 2011 were $1,068,087, an increase of $421,847, or 65.3% compared to $646,240 in 2010. Most of the increase is attributable to increase in operating expenses in Colombia. Colombian oil production and pipeline operating expenses increased by $306,229 and $108,553, respectively, in 2011 compared to 2010. Operating expenses as a percentage of total revenues decreased to 30.4% in 2011 from 35.2% in 2010, as the increase in revenues exceeded the increase in operating expenses.

 

General and Administrative Expenses

 

General and administrative expenses in 2011 were $1,686,686, an increase of $297,147, or 21.4% compared to $1,389,539 in 2010. The increase is due primarily to a $162,738 increase in compensation, a $69,313 increase in professional services, a $33,549 increase in travel and $31,801 increase in printing. General and administrative expenses as a percentage of total revenues decreased to 48.0% in 2011 from 75.8% in 2010, as the increase in revenues exceeded the increase in operating expenses.

 

Equity Tax

 

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 2010 and 2011 is comprised of both current equity taxes as well as taxes that were assessed by DIAN on Cimarrona’s operations in 2001 and 2003 prior to its ownership by us.

 

16
 

  

           Increase/(Decrease) 
   2011   2010   Amount   Percentage 
Current Equity Tax  $127,776   $145,957   $(18,181)   -12.5%
2001/2003 Tax Years   322,288    883,742    (561,454)   -63.5%
Total Equity Tax  $450,064   $1,029,699   $(579,635)   -56.3%

 

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 and believe that we may be able to make the 2003 tax payments over a three to five year period.

 

Depreciation, depletion and accretion

 

Depreciation, depletion and accretion were $429,689 in 2011 compared to and $351,463 in 2010. The increase in depreciation, depletion and accretion is primarily due to increase in depletion expense in the Guaduas field.

 

Stock Based Compensation Expense

 

Stock based compensation expense was $267,600 and $39,300 in 2011 and 2010, respectively. 2011 stock compensation expense related to the issuance of shares to four consultants, while 2010 stock based compensation expense related to shares issued to an officer and two consultants. All shares were immediately vested and the value was based on the stock price at the date of issuance.

 

Loss from Operations

 

Loss from operations was $386,403 and $1,622,464 in 2011 and 2010, respectively.

 

Interest Expense

 

Interest expense was $137,204 and $2,077 in 2011 and 2010. 2011 interest expense is comprised primarily of $100,000 cash interest on the Blackrock Note and $35,000 value of shares issued as interest on the Hoffman note. Both notes were issued and repaid during 2011 as more fully described in Note 5 of the financials.

 

Gain from Assignment of Leases

 

We recognized a gain from assignment of leases of $3,109,646 in 2011 compared to $0 in 2010. The 2011 gain related to the assignment of leases in the Nemaha Ridge prospect in Logan County, Oklahoma pursuant to the Participation Agreement.

 

Provision for Income Taxes

 

Provision for income taxes was $58,893 in 2011 compared to zero in 2010. Most of the provision for income taxes in 2011 relates to the federal alternative minimum tax resulting from the gain on assignment of leases.

 

Net Income/(Loss)

 

Net income was $2,535,599 in 2011 compared to a net loss of $1,621,470 in 2010. The $4,215,962 is due to primarily to the $3,109,646 gain from assignment of leases and the $1,236,061 improvement in operating loss.

 

17
 

  

Foreign Currency Translation

 

Foreign currency translation gain was $7,276 and $99,308 in 2011 and 2010, respectively. The Colombian Peso to Dollar Exchange Rate averaged 1,848 and 1,899 in 2011 and 2010, respectively. The Colombian Peso to Dollar Exchange Rate was 1,935 and 1,923 at December 31, 2011 and December 31, 2010, respectively.

 

Comprehensive Income/(Loss)

 

Comprehensive income was $2,542,875 in 2011 compared to a comprehensive loss of $1,522,162 in 2010.

 

Income/(Loss) per Share

 

Basic and diluted loss per share income was $0.05 in 2011 compared to a loss of $0.04 in 2010.

 

Liquidity and Capital Resources

 

We had working capital of $1,061,190 at December 31, 2011, compared to a working capital deficit of $653,503 at December 31, 2010. Working capital at December 31, 2011 consisted primarily of $1,904,023 of cash and equivalents and $293,739 of prepaid expenses, offset by $876,545 of accrued expenses and $323,699 of accounts payable. Working capital deficit at December 31, 2010, consisted primarily of $872,308 of accrued expenses and $202,880 of accounts payable, offset by $307,566 of cash and equivalents.

 

Net cash provided by operating activities was $57,649 in 2011 compared to net cash used by operating activities of $339,037 in 2010. The major components of net cash provided by operating activities in 2011 were the $2,535,599 net income and the $429,689 provision for depreciation and depletion, offset by the $3,109,646 gain on assignment of leases. The major components of net cash used by operating activities in 2010 were the $1,621,470 net loss, offset by the $745,052 increase in accounts payable and accrued expenses, the $351,463 provision for depreciation and depletion and the $146,675 decrease in accounts receivable.

 

Net cash used provided by investing activities was $1,559,853 in 2011 compared to net cash used by investing activities of $527,406 in 2010. Net cash provided by investing activities in 2011 consisted primarily of $5,339,797 net proceeds from assignment of leases offset by $3,754,863 investment in oil and gas properties. Net cash used in investing activities in 2010 consisted primarily of the $675,039 investments in oil and gas properties offset by the $154,289 reimbursement by Pacific for the pipeline.

 

Net cash used by financing activities was $0 and $3,535 in 2011 and 2010, respectively. 2011 consisted of $700,000 of borrowing on promissory notes offset by $700,000 of repayment of those promissory notes.

 

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 Hopper Property in Osage County, Oklahoma through independent contractors that operate producing wells for several small oil companies. Slawson is the operator in our Logan County, Oklahoma property. Pacific Rubiales, which owns 90.6% of the Guaduas field, is the operator of Cimarrona.

 

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.

 

18
 

  

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

 

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 Hopper Property in Osage County, Oklahoma, we sold oil at prices ranging from $82.73 to $95.73 per barrel in 2011 compared to $68.61 to $85.25 per barrel in 2010. In our Cimarrona Property in Colombia, we sold oil at prices ranging from $82.21 to $120.22 per barrel compared to $63.32 to $81.45 per barrel in 2010. The Colombian Peso to Dollar Exchange Rate averaged approximately 1,848 and 1,899 in 2011 and 2010, respectively. The Colombian Peso to Dollar Exchange Rate was 1,935 and 1,923 at December 31, 2011 and December 31, 2010, respectively.

 

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 production to Coffeyville in the United States and to Hocol in Colombia. However, in the event these customers discontinued oil and gas purchases, we believe we can replace them with other customers which would purchase the oil and gas at terms standard in the industry.

 

Critical Accounting Policies and Estimates

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations discusses our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. On an on-going basis, management evaluates our estimates and judgments, including those related to revenue recognition, recovery of oil and gas reserves, financing operations, and contingencies and litigation.

 

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 codified by FASB ASC topic 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.

 

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 December 31, 2011 and 2010, our oil production operations were conducted in Colombia and in the state of Oklahoma. 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.

 

19
 

  

In accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations,” as codified by FASB ASC topic 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.

 

We recognize 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 that 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 2011, we recognized sales of $62,375 and 635 barrels in excess of production. For 2010, we recognized sales of $108,918 and 1,344 barrels in excess of production. At December 31, 2011, the Company’s share of reserves exceeded 123,727 barrels.

 

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 8 Financial Statements and Supplementary Data

 

Our consolidated financial statements as of December 31, 2011 and 2010 and for the fiscal years ended December 31, 2011 and 2010 were audited by GKM, LLP, an independent registered public accounting firm, and have been prepared in accordance with generally accepted accounting principles pursuant to Regulation S-X as promulgated by the SEC. The aforementioned consolidated financial statements are included herein starting with page F-1.

 

20
 

 

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 

None

 

Item 9A Controls and Procedures

 

(a) Disclosure Controls and Procedures.

 

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 Exchange Act. Based upon their evaluation, the principal executive officer and principal financial officer 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 SEC (1) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (2) is accumulated and communicated to the Company’s management, including its principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure.

 

(b) Internal Controls Over Financial Reporting.

 

Management’s Report on Internal Control Over Financial Reporting

 

The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting. The internal control process has been designed under our supervision to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external reporting purposes in accordance with accounting principles generally accepted in the United States of America.

 

Management conducted an assessment of the effectiveness of the Company’s internal control over financial reporting as of December 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 December 31, 2011 is not effective. Based on this assessment, management has determined that, as of December 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 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.

 

21
 

  

(c) Changes to Internal Control Over Financial Reporting.

 

Except as indicated herein, there were no changes in the Company’s internal control over financial reporting during the quarter ending December 31, 2011 that have materially affected, or are reasonable likely to materially affect, the Company’s internal control over financial reporting.

 

ITEM 9B. Other Information

 

None

 

Item 10 Directors, Executive Officers and Corporate Governance.

 

The following table sets forth the names, ages, and offices held by our directors and executive officers:

 

Name   Position   Director Since   Age
Kim Bradford   President, Chief Executive Officer, Chief Financial Officer, Chairman   February 2007   59
Greg Franklin   Chief Geologist, Director   May 2005   55
Larry Ray   Director   September 2010   64

 

A list of current officers and directors appears above. The directors of the Company are elected annually by the stockholders. The officers serve at the pleasure of the Board of Directors (“BOD”). The directors do not receive fees or other remuneration for their services, but are reimbursed for their out-of-pocket expenses to attend board meetings.

 

The principal occupation and business experience during at least the last five years for each of the present directors and executive officers of the Company are as follows:

 

Kim Bradford: Mr. Bradford was elected President and Chief Executive Officer of the Company in January 2007 and elected to our board as Chairman effective February 2007. Mr. Bradford also served as our Chief Financial Officer and Secretary from January 2007 through November 9, 2007. In September 2008, Mr. Bradford once again became our Chief Financial Officer. In August 2005, Mr. Bradford co-founded Catalyst Consulting Partners LLC, a California based consulting firm that advised publicly traded companies and their management teams on executive search, shareholder communications, general media consulting, investor relations, website design and other corporate matters. In 2001, Mr. Bradford co-founded Decision Capital Management, LLC, the successor firm to Decision Capital Management LP, a Registered Investment Advisor firm which he founded in 1999. Prior to founding Decision Capital, Mr. Bradford has been involved in the brokerage business for over 25 years, both as an employee of major Wall Street firms, such as Merrill Lynch and Morgan Stanley, and as a principal in a NASD broker dealer firm specializing exclusively in natural resource based investments, such as oil and gas and precious metals mining.

 

Greg L. Franklin: Mr. Franklin has been our Chief Geologist since November 9, 2007 and a director of the Company since May 2005. Mr. Franklin previously served as a consultant to the Company in the role of a petroleum geologist since February 2005. Mr. Franklin has 25 years experience in the search, discovery, management and production of oil and gas. From March 1999 to February 2005 Mr. Franklin was a staff geologist for Barbour Energy. Mr. Franklin’s previous experience includes positions as Vice President for Gulf Coast Exploration and Development Company and geologist with Conoco. Mr. Franklin graduated with a Bachelor of Science in Geology from Oklahoma State University in 1980.

 

22
 

  

Larry Ray: Mr. Ray has been a director of the Company since September 2010. Mr. Ray has over 35 years of experience in all phases of international and domestic oil and gas production with both public and private companies. Since September 2007 he has been an independent oil and gas investor and consultant. Mr. Ray’s previous experience includes positions as President and Chief Operating Officer and interim Chief Financial Officer of Seven Seas Petroleum, an exploration and production company with primary operations in Colombia which was listed on both the Toronto and American Stock Exchanges, and President and Chief Operating Officer of The GHK Company, a large independent oil and gas company based in the mid-continent. Mr. Ray has been involved in drilling over 130 wells, constructing a 25,000 BBLS per day production facility and a 40 mile pipeline, evaluating and bidding on more than $250 million in properties and securing over $650 million in financing and farm-out agreements. Mr. Ray graduated with an MBA in Finance from Eastern New Mexico University in 1971 after receiving a Bachelor of Business Administration from the same institution in 1970. He is a member of the Association of International Petroleum Negotiators, the American Association of Professional Landmen, the American Association of Petroleum Geologist (Associate Member) and the Society of Petroleum Engineers.

 

Section 16(a) Beneficial Ownership Reporting Compliance

 

Section 16(a) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) requires our directors and officers, and the persons who beneficially own more than ten percent of our common stock, to file reports of ownership and changes in ownership with the SEC. Copies of all filed reports are required to be furnished to us pursuant to Rule 16a-3 promulgated under the Exchange Act. Based solely on the reports received by us and on the representations of the reporting persons, we believe that all required directors, officers and greater than ten percent shareholders complied with applicable filing requirements during the fiscal year ended December 31, 2011, except that Greg Franklin, Chief Geologist and Director of the Company, inadvertently did not timely file a Form 4 with the SEC in connection with sale of 50,000 shares between July 7, 2011 and July 12, 2011, which Form 4 was subsequently filed with the SEC on August 12, 2011.

 

Audit Committee

 

We do not have an Audit Committee, as our BOD during 2011 performed the same functions of an Audit Committee, such as: recommending a firm of independent certified public accountants to audit the annual financial statements; reviewing the independent auditors independence, the financial statements and their audit report; and reviewing management’s administration of the system of internal accounting controls. None of our directors are independent and no current director would qualify as an independent financial expert. We do not currently have a written audit committee charter or similar document.

 

Nominating Committee

 

We do not have a Nominating Committee or Nominating Committee Charter. Our BOD performed some of the functions associated with a Nominating Committee. We have elected not to have a Nominating Committee at this time. However, our BOD intends to continually evaluate the need for a Nominating Committee.

 

Code of Conduct

 

We have a written code of conduct that governs all of our officers, directors, employees and contractors. The code of conduct relates to written standards that are reasonably designed to deter wrongdoing and to promote:

 

(1)Honest and ethical conduct, including the ethical handling of actual or apparent conflicts of interest between personal and professional relationships;
(2)Full, fair, accurate, timely and understandable disclosure in reports and documents that are filed with, or submitted to, the Commission and in other public communications made by an issuer;
(3)Compliance with applicable governmental laws, rules and regulations;
(4)The prompt internal reporting of violations of the code to an appropriate person or persons identified in the code; and
(5)Accountability for adherence to the code.

 

23
 

  

Involvement in Certain Legal Proceedings

 

No director, person nominated to become a director, executive officer, promoter or control persons of our Company has been involved during the last ten years in any of the following events that are material to an evaluation of his ability or integrity:

 

·Bankruptcy petitions filed by or against any business of which such person was a general partner or executive officer either at the time of the bankruptcy or within two years prior to that time.
  
·Conviction in a criminal proceeding or being subject to a pending criminal proceeding (excluding traffic violations and other minor offenses).
  
·Being subject to any order, judgment or decree, not subsequently reversed, suspended or vacated, of any court of competent jurisdiction, permanently or temporarily enjoining, barring or suspending or otherwise limiting his involvement in any type of business, securities or banking activities, or
  
·Being found by a court of competent jurisdiction (in a civil action), the Securities and Exchange Commission or the Commodities Futures Trading Commission to have violated a federal or state securities or commodities law, and the judgment has not been reversed, suspended or vacated.

 

Compensation Committee

 

We currently do not have a compensation committee of the BOD. Until a formal committee is established, if at all, our entire BOD will review all forms of compensation provided to our executive officers, directors, consultants and employees including stock compensation and loans.

 

Item 11. Executive Compensation

 

Executive Officers

 

Our current executive officers are as follows:

  

Name   Age   Position
Kim Bradford   59   President, Chief Executive Officer, Chief Financial Officer
Greg Franklin   55   Chief Geologist

 

Pursuant to Securities Exchange Commission rules, our reportable “named executive officers” for the last two years include Kim Bradford, who serves as our Principal Executive Officer and Principal Financial Officer, as well as Greg Franklin, our Chief Geologist.

 

During the last two fiscal years, the following executive officers of our company have received total annual salary and bonus exceeding $100,000:

 

SUMMARY COMPENSATION TABLE
Name and principal
position
  Year   Salary   Bonus   Stock
Awards
   Nonequity
incentive plan
compensation
   Nonqualified
deferred
compensation
earnings
   All other
compensation
   Total 
Kim Bradford   2011   $244,615   $100,000   $0   $0   $0   $0   $344,615 
President, CEO and CFO   2010   $ 249,231   $0   $0   $0   $0   $0   $249,231
Greg Franklin   2011   $221,538   $30,000   $251,538   $0   $0   $0   $251,538 
Chief Geologist   2010   $249,599   $0   $25,000   $0   $0   $0   $274,599 

 

24
 

  

On November 9, 2007, the Company entered into an employment agreement with Kim Bradford to serve as President and Chief Executive Officer. The agreement was for two years ending November 30, 2009 (“Employment Period”) and allowed Mr. Bradford to be eligible for an annual bonus as determined by the Board of Directors. In the event Mr. Bradford’s employment is terminated for a change of control, then he shall be eligible to receive, in one lump payment, the greater of (i) annual base salary in effect immediately prior to the change of control and (ii) the remaining base salary in effect immediately prior to the Change of control owed to the officer until the end of the Employment Period. Mr. Bradford’s employment agreement included an annual base salary of $144,000 and a signing bonus of $150,000. Mr. Bradford’s annual base salary was subsequently increased to $240,000 during 2009. In 2011, Mr. Bradford received a cash bonus of $100,000 and an increase in base salary to $300,000 pursuant to a verbal agreement. The Company is currently negotiating with Mr. Bradford on a new employment contract.

 

On November 9, 2007, the Company entered into an employment agreements with Greg Franklin to serve as Chief Geologist. The agreement was for two years ending November 30, 2009 (“Employment Period”) and allowed Mr. Franklin to be eligible for an annual bonus as determined by the Board of Directors. In the event that Mr. Franklin’s employment is terminated for a change of control, then he shall be eligible to receive, in one lump payment, the greater of (i) annual base salary in effect immediately prior to the change of control and (ii) the remaining base salary in effect immediately prior to the change of control owed to the officer until the end of the Employment Period. Mr. Franklin’s employment included an annual base salary of $120,000 and a signing bonus of 2,000,000 shares of the Company’s Stock, which vested 100% on January 1, 2009. Mr. Franklin’s annual base salary was subsequently increased to $240,000 during 2009 pursuant to a verbal agreement. On September 1, 2010, the Company entered into a new two-year employment agreement with Mr. Franklin to continue serving as Chief Geologist. Mr. Franklin’s agreement included an annual base salary of $240,000 and the issuance of 1,000,000 shares of the Company’s stock, which vested immediately upon issuance. In 2011, Mr. Franklin received a $30,000 bonus and elected to reduce his salary to $210,000 pursuant to a verbal agreement.

 

Mr. Ray, who became a director in September 2010, received $0 and $35,000 in 2011 and 2010 for consulting services provided to the Company. In addition, Mr. Ray received 500,000 shares of the Company’s stock in 2010, which vested at the time of issuance and were valued at $12,500, based on the closing stock price at the date of issuance.

 

We do not have any other contractual arrangements with our executive officers, promoters or directors, nor do we have any compensatory arrangements with our executive officers, promoters or directors other than as described below:

 

Outstanding Equity Awards at Fiscal Year-End

 

    Option Awards   Stock Awards  

Name

(a)

 

Number of

Securities

Underlying

Unexercised

Options (#)

Exercisable

(b)

   

Number of

Securities

Underlying

Unexercised

Options (#)

Unexercisable

(c)

   

Equity

Incentive

Plan Awards

Number of

Securities

Underlying

Unexercised

Unearned

Options (#)

(d)

   

Option

Exercise

Price

($)

(e)

 

Option

Expiration

Date

(f)

 

Number of

Shares or

Units of

Stock That

Have Not

Vested (#)

(g)

   

Market Value

of Shares or 

Units of Stock

That Have

Not Vested

($)

(h)

   

Equity

Incentive

Plan

Awards:

Number of

Unearned

Shares, Units

or Other

Rights That

Have Not

Vested (#)

(i)

   

Equity Incentive

Plan Awards:

Market or Payout

Value of Unearned

Shares, Units or

Other Rights That

Have Not Vested

($)

(j)

 
Kim Bradford                                                
Greg Franklin                                                

 

25
 

  

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

 

The following table shows information as of March 15, 2012 with respect to each beneficial owner of more than five percent of the Company’s Common stock:

 

Name and Address of   Common Stock   Percent
Beneficial Owner   Beneficially Owned   of Class
Kim Bradford   7,035,000   14.7%
2445 5th Avenue, Suite 310        
San Diego, CA 92101        
E. Peter Hoffman, Jr. [1]   5,639,119   11.8%
6301 N. Western        
Suite 260        
Oklahoma City, OK 73118        
Mustang Capital Venture, LLC [2]   5,250,000   10.9%
10101 Reunion Place, Suite 1000        
San Antonio, TX 78216        
Greg L. Franklin   3,950,000   8.2%
2445 5th Avenue, Suite 310        
San Diego, CA 92101        
Sunstone Corporation [3]   3,875,000   7.9%
101 N. Robinson, Suite 800        
Oklahoma City, OK 73102        
Larry Ray   600,000   1.3%
2445 5th Avenue, Suite 310        
San Diego, CA 92101        

 

The percentage ownership is based on 47,974,775 shares outstanding at March 21, 2012

 

[1] Information is derived from Schedule 13D Amendment #2 filed by Mr. Hoffman, Jr. on December 29, 1011.

[2] Information is derived from Schedule 13D filed by Mustang Capital Venture, LLC on March 16, 2009.

[3] Information is derived from Schedule 13D filed by Sunstone Corporation on April 28, 2010. Includes 1,250,000 warrants to purchase shares of common stock exercisable within 60 days.

 

26
 

  

The following table shows information as of March 21, 2012 with respect to each of the beneficial owners of the Company’s Common stock by its executive officers, directors and nominee individually and as a group:

 

Name and Address of   Common Stock   Percent
Beneficial Owner   Beneficially Owned   of Class
Kim Bradford   7,035,000   14.7%
2445 5th Avenue, Suite 310        
San Diego, CA 92101        
Greg L. Franklin   3,950,000   8.2%
2445 5th Avenue, Suite 310        
San Diego, CA 92101        
Larry Ray   600,000   1.3%
2445 5th Avenue, Suite 310        
San Diego, CA 92101        
Officers and Directors as a   11,585,000   24.1%
Group (3 people)        

 

The percentage ownership is based on 47,974,775 shares outstanding at March 21, 2012.

 

There are no family relationships among the directors and executive officers.

 

Changes in Control

 

On December 28, 2006, a change of control occurred when Kim Bradford, our Chief Executive Officer, President, Chief Financial Officer and Chairman, along with other investors entered into a transaction with the Company whereby for a $470,875 promissory note, the Company issued a total of 18,835,000 shares of Common stock, or approximately 64% of the total shares outstanding. The shares were valued based on the approximate asset value per share prior to the transaction. Of the $470,875 promissory notes, Mr. Bradford issued a note in the amount of $151,375 for the purchase of 6,055,000 shares. In December 2007, Mr. Bradford paid in full his note plus accrued interest. The notes matured December 31, 2011 and at December 31, 2011, there are notes receivable for $95,000, representing 3,800,000 shares. The Company is currently attempting to collect the notes receivable.

 

Item 13 Certain Relationships and Related Transactions

 

There have been no transactions during the last two years, or proposed transactions, to which we were or are to be a party in which any of the following persons had or is to have a direct or indirect material interest:

 

·any officer or director;
·any nominee for election as a director;
·any beneficial owner of more than five percent of our voting securities;
·any member of the immediate family of any of the above persons.

 

Director Independence

 

Our BOD is made up of Kim Bradford, our President, Chief Executive Officer and Chief Financial Officer, Greg Franklin, our Chief Geologist and Larry Ray. Our common stock trades on the Over-the-Counter Bulletin Board. Because we are traded on the Over-the-Counter Bulletin Board, we are not currently subject to corporate governance standards of listed companies, which require, among other things, that the majority of the BOD be independent.

 

27
 

  

Since we are not currently subject to corporate governance standards relating to the independence of our directors, we choose to define an “independent” director in accordance with applicable independence standards required of issuers listed on the NASDAQ Capital Market. NASDAQ Marketplace Rule 4200(a)(15) defines an “Independent director” as a person other than an executive officer or employee of the company or any other individual having a relationship which, in the opinion of the issuer’s BOD, would interfere with the exercise of independent judgment in carrying out the responsibilities of a director. At this time, the Board has determined that none of its directors are independent under the above definition.

 

Item 14. Principal Accounting Fees and Services 

 

Selection of our Independent Registered Public Accounting Firm is made by the BOD. GKM LLP has been selected as our Independent Registered Public Accounting Firm for the current fiscal year. All audit and non-audit services provided by GKM LLP are pre-approved by the BOD which gives due consideration to the potential impact of non-audit services on auditor independence.

 

In accordance with Independent Standard Board Standards No. 1 (Independence Discussion with Audit Committees), we received a letter and verbal communication from GKM LLP that it knows of no state of facts which would impair its status as our independent public accountants. The BOD has considered whether the non-audit services provided by GKM LLP are compatible with maintaining its independence and has determined that the nature and substance of the limited non-audit services have not impaired GKM LLP s status as our Independent Registered Public Accounting Firm.

 

AUDIT FEES

 

The aggregate fees billed and anticipated by our auditor for professional services rendered for the audit of our annual financial statements and for the reviews of the financial statements included in our Quarterly Reports on Form 10-Q were $85,000 for both 2011 and 2010.

 

TAX FEES

 

Our auditors did not bill us for any tax services during 2011 and 2010.

 

ALL OTHER FEES

 

Our auditors did not bill us for any other services during 2011 and 2010.

 

28
 

 

Part IV

 

Item 15. Exhibit, Financial Statements Schedules

 

Exhibit No.   Description
  2.1   Plan of Reorganization and Agreement of Merger, dated June 18, 2007 (1)
  3.1   Articles of Incorporation of Osage Exploration and Development, Inc. (1)
  3.2   Bylaws of Osage Exploration and Development, Inc. (1)
10.1   Agreement for Acquisition of Oil and Gas Leaseholds between Conquest Exploration Company, LLC, David Farmer, Charles Volk, Jr. and Osage Energy Company, LLC dated November 10, 2004. (1)
10.2   Assignment and Bill of Sale between Conquest Exploration Company, LLC and Osage Energy Company, LLC dated January 24, 2005. (1)
10.3   $250,000 Note and Security Agreement with Vision Opportunity Master Fund, Ltd. dated February 13, 2007. (1)
10.4   $1,100,000 Unsecured Convertible Promissory Note with Marie Baier Foundation dated July 16, 2007. (2)
10.5   Form of Warrant issued to Marie Baier Foundation in connection with the $1,100,000 Unsecured Convertible Promissory Note. (2)
10.6   Rosa Blanca Carried Interest Agreement dated June 21, 2007. (3)
10.7   2007 Equity Based Compensation Plan (4)
10.8   Purchase and Sale Agreement for the purchase of the Hansford Property (4)
10.8.1   Extension Agreement with Pearl Resources, Corp. for the Hansford Property (5)
10.8.2   Letter from Charles Volk regarding Ownership of the Hansford Property (6)
10.9   Consulting Agreement dated January 1, 2007 with Greg Franklin (4)
10.10   Consulting Agreement dated February 1, 2007 with Ran Furman (4)
10.11   Form of Stock Subscription Receivable dated December 28, 2006 (4)
10.11.1   Form of Amendment #1 to Stock Subscription Receivable dated August 1, 2007 (4)
10.12   Oil and Gas Mining Lease with the Osage Nation dated July 21, 1999 (4)
10.13   Office lease agreement with Catalyst Consulting Partners, LLC (4)
10.14   Employment Agreement with Kim Bradford, President and CEO (7)
10.15   Employment Agreement with Greg Franklin, Chief Geologist (7)
10.15.1   Restricted Stock Agreement with Greg Franklin, Chief Geologist (7)
10.16   Employment Agreement with Ran Furman, Chief Financial Officer (7)
10.16.1   Restricted Stock Agreement with Ran Furman, Chief Financial Officer (7)
10.17   Office Lease, dated February 1, 2008, by and between Osage Exploration & Development, Inc. and Fifth & Laurel Associates, LLC. (8)
10.18   Membership Purchase Interest between Osage Exploration and Development, Inc. and Sunstone Corporation dated April 8, 2008 (9)
10.18.1   Warrant to purchase 1,125,000 shares of common stock of Osage Exploration and Development, Inc. issued to Sunstone Corporation dated April 8, 2003 (9)
10.19   Independent Contractor Agreement between Osage Exploration and Development, Inc. and E. Peter Hoffman, Jr. dated July 2, 2008 (10)
10.20   Agreement between Lewis Energy Colombia, Inc., Gold Oil Plc Sucursal Colombia and Osage Exploration and Development, Inc. and Osage Exploration and Development, Inc., Sucrusal Colombia dated March 3, 2009 (11)
10.21   Settlement Agreement between Lewis Energy Colombia, Inc., Gold Oil Plc Sucursal Colombia, EMPESA, SA, and Osage Exploration and Development, Inc. Sucrusal Colombia dated September 15, 2009 (12)
10.22   Employment Agreement with Greg Franklin, Chief Geologist (13)
10.22.1   Restricted Stock Agreement with Greg Franklin, Chief Geologist (13)
10.23   $500,000 Promissory Note to Blackrock Management, Inc. (14)
10.23.1   Escrow Agreement between Osage Exploration and Development, Inc., Blackrock Management, Inc. and Robertson & Williams (14)

 

29
 

  

10.23.2   Assignment of Oil and Gas Leases between Osage Exploration and Development, Inc. and Blackrock Management, Inc. (14)
10.23.3   Mortgage between Osage Exploration and Development, Inc. and Blackrock Management, Inc. (14)
10.24   Reddy Petroleum Company reserve report for the Osage Property as of December 31, 2010 (15)
10.24.1   Reddy Petroleum Company reserve report for the Osage Property as of December 31, 2011 (*)
10.25   Petrotech Engineering Ltd. reserve report for the Cimarrona property as of December 31, 2010 (15)
10.25.1   Petrotech Engineering Ltd. reserve report for the Cimarrona property as of December 31, 2010 (*)
21.1   List of Subsidiaries(*)
31.1   Certification of Chief Executive pursuant to Rule 13a-14 and Rule 15d-14(a), promulgated under the Securities and Exchange Act of 1934, as amended.(*)
31.2   Certification of Chief Financial pursuant to Rule 13a-14 and Rule 15d-14(a), promulgated under the Securities and Exchange Act of 1934, as amended.(*)
32.1   Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Chief Executive Officer)(*)
32.2   Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Chief 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 by reference to Osage’s Form 10-SB filed July 6, 2007
(2)Incorporated by reference to Osage’s Form 8-k filed July 17, 2007
(3)Incorporated by reference to Osage’s Form 8-k filed August 13, 2007
(4)Incorporated by reference to Osage’s Form 10-SB Amendment No. 1 filed August 27, 2007
(5)Incorporated by reference to Osage’s Form 10-SB Amendment No. 2 filed October 15, 2007
(6)Incorporated by reference to Osage’s Form 10-SB Amendment No. 3 filed November 19, 2007
(7)Incorporated by reference to Osage’s Form 10-SB Amendment No. 5 filed December 28, 2007
(8)Incorporated by reference to Osage’s Form 8-k filed March 4, 2008
(9)Incorporated by reference to Osage’s Form 8-k filed April 10, 2008
(10)Incorporated by reference to Osage’s Form 8-k filed July 7, 2008
(11)Incorporated by reference to Osage’s Form 8-k filed March 5, 2009
(12)Incorporated by reference to Osage’s Form 8-k filed September 17, 2009
(13)Incorporated by reference to Osage’s Form 8-k filed September 7, 2011
(14)Incorporated by reference to Osage’s Form 8-k filed January 26, 2011
(15)Incorporated by reference to Osage’s Form 10-K/a filed September 7, 2011
(*)Filed with this Form 10K

 

30
 

  

SIGNATURES

 

In accordance with the requirements of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

OSAGE EXPLORATION & DEVELOPMENT, INC.

 

BY: /S/ KIM BRADFORD  
  Kim Bradford  
  President and C.E.O.  

 

Dated: March 23, 2012

 

BY: /S/ KIM BRADFORD  
  Kim Bradford  
  Chief Financial Officer  

 

Dated: March 23, 2012

 

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

 

Signature   Title   Date
         
    President, Chief Executive Officer, Chief Financial    
/s/ KIM BRADFORD   Officer and Chairman   March 23, 2012
Kim Bradford   (Principal Executive and Financial Officer)    
         
/s/ GREG FRANKLIN   Chief Geologist and Director   March 23, 2012
Greg Franklin        
         
/s/ LARRY RAY   Director   March 23, 2012
Larry Ray        

 

31
 

 

OSAGE EXPLORATION AND DEVELOPMENT, INC.

INDEX TO FINANCIAL STATEMENTS

 

Set forth below are the following consolidated financial statements for our company for the years ended December 31, 2011 and 2010:

 

  Page
   
Report of Independent Registered Public Accounting Firm F-1
Consolidated Balance Sheets as of December 31, 2011 and 2010 F-2
Consolidated Statements of Operations for Years Ended December 31, 2011 and 2010 F-3
Consolidated Statements of Stockholders’ Equity for Years Ended  
December 31, 2011 and 2010 F-4
Consolidated Statements of Cash Flows for Years Ended December 31, 2011 and 2010 F-5
Notes to Consolidated Financial Statements F-6

  

32
 

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

To the Board of Directors and Shareholders

Osage Exploration and Development, Inc.

San Diego, CA

 

We have audited the accompanying consolidated balance sheets of Osage Exploration and Development, Inc. (Company), as of December 31, 2011 and 2010, and the related consolidated statements of operations, stockholders’ equity, and cash flows for the years ended December 31, 2011 and 2010. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the consolidated financial statements based on our audits.

 

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

 

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Osage Exploration and Development, Inc. and Subsidiaries as of December 31, 2011, and the results of its operations and its cash flows for the years ended December 31, 2011 and 2010, in conformity with accounting principles generally accepted in the United States of America.

 

The accompanying consolidated financial statements have been prepared assuming the Company will continue as a going concern. As discussed in Note 1 to the consolidated financial statements, the Company has suffered recurring losses from operations and has an accumulated deficit as of December 31, 2011. These conditions raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regards to these matters are also described in Note 1 to the consolidated financial statements. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

 

/s/ GKM, LLP  

 

GKM, LLP

Encino, California

March 21, 2012

 

F-1
 

 

OSAGE EXPLORATION AND DEVELOPMENT, INC.

CONSOLIDATED BALANCE SHEETS

As of December 31, 2011 and 2010

 

   2011   2010 
ASSETS          
           
Current Assets:          
Cash and equivalents  $1,904,023   $307,566 
Accounts receivable   122,565    9,994 
Joint Operating Account   235,779    64,484 
Prepaid expenses   57,960    39,441 
Total Current Assets   2,320,327    421,485 
           
Property and Equipment, at cost:          
Oil and gas properties and equipment (Successful Efforts Method)   4,331,417    2,818,833 
Capitalized asset retirement costs   46,146    46,146 
Other property & equipment   79,942    54,861 
    4,457,505    2,919,840 
Less: accumulated depletion, depreciation and amortization   (1,345,719)   (939,639)
    3,111,786    1,980,201 
           
Bank CD pledged for Bond   30,000    30,000 
Note Receivable   11,000    - 
           
Total Assets  $5,473,113   $2,431,686 
           
LIABILITIES AND STOCKHOLDERS’ EQUITY          
           
Current Liabilities:          
Accounts payable  $323,699   $202,880 
Income Taxes Payable   58,893    - 
Accrued Expenses   876,545    872,308 
Total Current Liabilities   1,259,137    1,075,188 
           
Liability for Asset Retirement Obligations   59,950    57,746 
           
Total Liabilities   1,319,087    1,132,934 
           
Commitments and Contingencies          
           
Stockholders’ Equity:          
Common stock, $0.0001 par value, 190,000,000 shares          
authorized; 47,884,775  and 46,649,775 shares issued and   4,788    4,665 
outstanding as of December 31, 2011 and 2010, respectively          
Additional-Paid-in-Capital   12,107,920    11,795,844 
Stock Purchase Notes Receivable   (95,000)   (95,000)
Accumulated Deficit   (7,558,080)   (10,093,679)
Accumulated Other Comprehensive Loss - Currency Translation Loss   (305,602)   (312,878)
Total Stockholders’ Equity   4,154,026    1,298,952 
           
Total Liabilities and Stockholders’ Equity  $5,473,113   $2,431,886 

 

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

 

F-2
 

  

OSAGE EXPLORATION AND DEVELOPMENT, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

For Years Ended December 31, 2011 and 2010

 

   2011   2010 
Operating Revenues          
Oil Sales  $1,920,834   $1,468,070 
Pipeline Sales   1,594,889    365,707 
Total Operating Revenues   3,515,723    1,833,777 
           
Operating Costs and Expenses          
Well Operating Costs   1,068,087    646,240 
Equity Tax   450,064    1,029,699 
Depreciation, Depletion and Accretion   429,689    351,463 
Stock Based Compensation   267,600    39,300 
General and Administrative   1,686,686    1,389,539 
Total Operating Costs and Expenses   3,902,126    3,456,241 
           
Operating (Loss)   (386,403)   (1,622,464)
           
Other Income (Expenses):          
Interest Income   8,453    3,071 
Interest Expense   (137,204)   (2,077)
Gain from Assignment of Leases   3,109,646    - 
           
Income/(Loss) before Income Taxes   2,594,492    (1,621,470)
           
Provision for Income Taxes   58,893    - 
           
Net Income/(Loss)   2,535,599    (1,621,470)
           
Other Comprehensive Income, net of tax:          
Foreign Currency Translation Adjustment   7,276    99,308 
Other Comprehensive Income   7,276    99,308 
           
Comprehensive Income/(Loss)  $2,542,875   $(1,522,162)
           
Basic and Diluted Income/(Loss) per Share  $0.05   $(0.04)
           
Weighted average number of common share and common share equivalents used to compute basic and diluted Income/(Loss) per Share   47,283,652    46,069,967 

 

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

 

F-3
 

  

OSAGE EXPLORATION AND DEVELOPMENT, INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

For Years Ended December 31, 2011 and 2010

 

                       Accumulated     
           Additional   Stock       Other     
   Common Stock   Paid-In   Purchase   Accumulated   Comprehensive   Total 
   Shares   Amount   Capital   Note Receivable   Deficit   Income/(Loss)   Equity 
Balance at January 1, 2010   46,959,775   $4,696   $11,804,013   $(142,500)  $(8,472,209)  $(412,186)  $2,781,814 
Issuance of Shares for Professional Services   1,590,000    159    39,141                   39,300 
Cancellation of Shares of Former CEO   (1,900,000)   (190)   (47,310)   47,500              - 
Net Loss for the year                       (1,621,470)        (1,621,470)
Foreign Exchange Translation Adjustment                            99,308    99,308 
Balance at December 31, 2010   46,649,775    4,665    11,795,844    (95,000)   (10,093,679)   (312,878)   1,298,952 
Issuance of Shares for Professional Services   985,000    98    277,101                   277,199 
Issuance of Shares for Interest   250,000    25    34,975                   35,000 
Net Income for the year                       2,535,599         2,535,599 
Foreign Exchange Translation Adjustment                            7,276    7,276 
Balance at December 31, 2011   47,884,775   $4,788   $12,107,920   $(95,000)  $(7,558,080)  $(305,602)  $4,154,026 

 

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

 

F-4
 

 

OSAGE EXPLORATION AND DEVELOPMENT, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

For Years Ended December 31, 2011 and December 31, 2010

 

   2011   2010 
         
Cash flows from Operating Activities:          
Net Income/(Loss)  $2,535,599   $(1,621,470)
Adjustments to reconcile net income/(loss) to net cash provided/(used) by operating activites:          
Gain on assignment of leases   (3,109,646)   - 
Shares issued for interest   35,000    - 
Shares issued for services   277,199    39,300 
Accretion of asset retirment obligation   2,204    2,004 
Provision for depletion, depreciation, amortization and valuation allowance   429,689    351,463 
Changes in operating assets and liabilities:          
Decrease /(increase) in accounts receivable   (124,505)   146,675 
(Increase) in Joint Operating Account   (158,944)   (211,090)
(Increase)/decrease in prepaid expenses   (18,517)   (2,061)
Increase in accounts payable   112,035    (20,238)
Increase in Income Taxes Payable   58,893    - 
Increase in accrued expenses   18,642    976,380 
Net cash provided/(used) by operating activities   57,649    (339,037)
           
Cash flows used in Investing Activities:          
Net proceeds from assignment of leases   5,339,797    - 
Reimbursement by Pacific for pipeline   -    154,289 
Investments in Oil & Gas properties   (3,754,863)   (675,039)
Purchase of Non Oil & Gas property   (25,081)   (6,656)
Net cash used by investing activities   1,559,853    (527,406)
           
Cash flows provided by Financing Activities:          
Borrowing on promissory notes   700,000    - 
Payments on Promissory notes   (700,000)   (3,535)
Net cash (used)/provided by financing activities   -    (3,535)
           
Effect of exchange rate on cash and equivalents   (21,045)   2,555 
           
Net increase/(decrease) in cash and equivalents   1,596,457    (867,423)
           
Cash and equivalents beginning of year  $307,566   $1,174,989 
           
Cash and equivalents at end of year  $1,904,023   $307,566 
           
SUPPLEMENTAL CASH FLOW INFORMATION:          
Cash paid for Interest  $100,000   $74 
Cash paid for Taxes  $3,615   $1,127 

 

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

 

F-5
 

 

OSAGE EXPLORATION AND DEVELOPMENT, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2011 and 2010

 

1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 

NATURE OF OPERATIONS AND BUSINESS COMBINATION

 

Osage Exploration and Development, Inc. (“Osage” or “the Company”) 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 that 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.”

 

The Company has an accumulated deficit of $7,558,080 at December 31, 2011 and $10,093,679 at December 31, 2010. In 2011, the Company recognized a one-time gain of $3,109,646 from assignment of leases in Logan County, OK. Excluding this gain, the Company would have recorded a net loss for 2011. 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.

 

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) raising additional capital and/or obtaining financing ; (b) increasing our current production; and (c) controlling overhead and expenses.

 

There is no assurance the Company can successfully accomplish these steps and it is uncertain the Company will achieve a profitable level of operations and obtain additional financing. There can be no assurance that any 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.

 

F-6
 

  

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.

 

RECLASSIFICATIONS

 

Certain amounts included in the prior year financial statements have been reclassified to conform to the current year’s presentation. In 2010, equity tax was presented as part of general and administrative expenses. These reclassifications have no affect on the reported net loss in 2010.

 

RISK FACTORS RELATED TO CONCENTRATION OF SALES AND PRODUCTS

 

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

 

USE OF ESTIMATES

 

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“US GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Management used significant estimates in determining the carrying value of its oil and gas producing assets and the associated depreciation and depletion expense related to sales’ volumes. The significant estimates included the use of proved oil and gas reserve volumes and the related present value of estimated future net revenues there-from (See Note 16: Supplemental Information About Oil and Gas Producing Activities).

 

CASH AND EQUIVALENTS

 

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

 

FAIR VALUE OF FINANCIAL INSTRUMENTS

 

The Company measures its financial assets and liabilities in accordance with US GAAP. For certain of the Company’s financial instruments, including accounts receivable (trade and related party), notes receivable and accounts payable (trade and related party), and accrued expenses, the carrying amounts approximate fair value due to their short maturities. The amounts owed for notes payable also approximate fair value because interest rates and terms offered to the Company are at current market rates.

 

CONCENTRATION OF CREDIT RISK

 

Financial instruments that potentially subject the Company to concentrations of credit risk are: cash and accounts receivable arising from its normal business activities. The Company places its cash in what it believes are credit-worthy financial institutions. However, the Company’s cash balances have exceeded the FDIC insured levels at various times during 2011 and 2010. At December 31, 2011, the Company had $1,202,262 in cash in excess of federally insured limits. The Company maintains cash accounts only at large, high quality financial institutions and believes the credit risk associated with cash held in back exceeding the FDIC insured levels is remote.

 

F-7
 

  

In the U.S., the Company currently sells all of its oil production to one customer, Coffeyville Resources Refining & Marketing, LLC (“Coffeyville”). In Colombia, the Company currently sells all of its oil production to one customer, Hocol, S.A. and has only one customer for its pipeline, Pacific Rubiales Energy Corp. (“Pacific”) However, the Company believes it can sell all its production to many different purchasers, most of whom pay similar prices that vary with the international spot market prices. The Company controls credit risk related to accounts receivable through credit approvals, credit limits and monitoring procedures. The Company routinely assesses the financial strength of its customers and, based upon factors surrounding the credit risk, establishes an allowance, if required, for uncollectible accounts and, as a consequence, believes that its accounts receivable credit risk exposure beyond such allowance is limited. The Company had no allowance as of December 31, 2011 and 2010. The analysis was based on its evaluation of specific customers’ balances and the collectability thereof.

 

OIL AND GAS PROPERTIES

 

Osage is an exploration and production oil and natural gas company with proved reserves and existing production in Oklahoma and in the country of Colombia. In 2005, we purchased 100% of the working interest in certain producing oil and natural gas leases located in Osage County, Oklahoma, referred to herein as the Osage Property, which property consists of twenty three wells, ten of which are producing, on 480 acres. We are the operators of this property.

 

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 purchase price consisted of 2,750,000 shares of the Company’s common stock and a warrant to purchase 1,125,000 shares of the Company’s common stock at $1.25 per share and expiring April 8, 2013. In addition, we issued 50,000 shares of common stock to Energy Capital Solutions, LP for their role as financial advisor and $22,500 to an individual, as a finder’s fee.

 

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 indicates 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 Ecopetrol could become a 50% partner in 2012 which would 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 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.

 

F-8
 

  

On April 21, 2011, we entered into a participation agreement (“Participation Agreement”) with Slawson Exploration Company (“Slawson”) and U.S. Energy Development Corporation (“USE”, Slawson and USE, together, the “Parties”). Pursuant to the terms of the Participation Agreement, Slawson and USE acquired 45% and 30% respectively, of our 10,000 acre Nemaha Ridge prospect in Logan County, OK 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 cost of the wells. 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. Since the Participation Agreement was signed, Slawson and USE acquired 45% and 30%, respectively, of an additional 11,844 acres that we offered to them. We are continuing to acquire additional acreage in the Nemaha Ridge prospect and we will offer the additional acreage to the Parties, at our cost, subject to their acceptance. At December 31, 2011, we had 5,181 net acres (20,723 gross) leased in Logan County. In December 2011, we began drilling the Wolfe 1-29H, our first well in Logan County and in January 2012, we began drilling the Krittenbrink 2-36H, our second well in Logan County.

 

In addition to accumulating leases in Logan County, in 2011, we began to acquire leases in Pawnee County, Oklahoma, targeting the Mississippian formation and as of December 31, 2011, we had 915 net acres (1,624 gross) leased in Pawnee County. In July 2011, we entered into an agreement with B&W Exploration, Inc. (“B&W”) whereby we purchased from B&W the Pawnee County prospect 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.

 

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 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. The Woodford shale rock is silica-rich. It is very brittle and generates lots of natural fractures. It also behaves very well when modern fracturing techniques are applied. At December 31, 2011, we had 2,517 net (6,473 gross) acres leased in Coal County.

 

The Company follows the “successful efforts” method of accounting for its oil and gas exploration and development activities, as set forth in the Statement of Financial Accounting Standards (“SFAS”) No. 19, as codified by FASB ASC topic 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 proved unsuccessful are charged to operations in the period the leasehold costs are proved unsuccessful. Costs of carrying and retaining unproved properties are expensed as incurred.

 

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. The costs of drilling and equipping development wells are capitalized, whether the wells are successful or unsuccessful.

 

The provision for depreciation and depletion of oil and gas properties is computed by the unit-of-production method. Under this method, the Company computes 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 December 31, 2011 and 2010, the Company’s oil production operations are conducted in the United States of America and in the country of Colombia. 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 costs associated with unevaluated properties relate to projects which were undergoing exploration or development activities or in which the Company intends to commence such activities in the future. The Company will begin to amortize these costs when proved reserves are established or impairment is determined. Management believes no such impairment exists at December 31, 2011 and 2010.

 

F-9
 

  

In accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations”, as codified by FASB ASC topic 410, the Company reports a liability for any legal retirement obligations on its 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 asinterest 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.

 

OTHER PROPERTY AND EQUIPMENT

 

Non-oil and gas producing properties and equipment are stated at cost; major renewals and improvements are charged to the property and equipment accounts; while replacements, maintenance and repairs, which do not improve or extend the lives of the respective assets, are expensed as incurred. At the time property and equipment are retired or otherwise disposed of, the asset and related accumulated depreciation accounts are relieved of the applicable amounts. Gains or losses from retirements or sales are credited or charged to 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 fifteen years of the assets.

 

IMPAIRMENT OF LONG-LIVED ASSETS

 

Effective January 1, 2002, the Company adopted SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS 144”), as codified by the FASB ASC topic 360 (“ASC 360”), which addresses financial accounting and reporting for the impairment or disposal of long-lived assets and supersedes SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of,” and the accounting and reporting provisions of APB Opinion No. 30, “Reporting the Results of Operations for a Disposal of a Segment of a Business.” 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. The Company believes that there were no significant impairments of its long-lived assets for the years ended December 31, 2011 and 2010.

 

F-10
 

  

REVENUE RECOGNITION

 

The Company recognizes 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 the Company, (iii) a fixed sales price has been included in such invoice, and (iv) collection from such customer is probable.

 

We recognize 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 that 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 2011, we recognized sales of $62,375 and 635 barrels in excess of production. For 2010, we recognized sales of $108,918 and 1,344 barrels in excess of production. At December 31, 2011, the Company’s share of reserves exceeded 98,855 barrels.

 

STOCK BASED COMPENSATION

 

The Company accounts for its stock-based compensation in accordance with SFAS No. 123R, “Share-Based Payment, an Amendment of FASB Statement No. 123”, as codified by FASC ASC topic 718. 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.

 

In 2011, we issued 985,000 shares to four consultants. All of the shares vested immediately and were valued at the stock price at the time of issuance with a total value of $277,199. $9,600 of the shares issued were recorded as prepaid expenses and will be expensed in the first quarter of 2012, as those shares were issued for work to be performed in the first quarter of 2012. In 2010, we issued 90,000 shares to a consultant, 500,000 shares to a board member and 1,000,000 shares to an officer of the Company in conjunction with a new employment agreement. All of the shares vested immediately and were recorded as stock based compensation expense in 2010 and valued at the stock price at the time of issuance with a total value of $39,300.

 

IMPACT OF RECENT ACCOUNTING PRONOUNCEMENTS

 

Recent Pronouncements

 

In January 2010, the FASB issued ASU 2010-03, “Oil and Gas Reserve Estimations and Disclosures” (ASU 2010-03). This update aligns the current oil and gas reserve estimation and disclosure requirements of ASC Topic 932 with the changes required by the SEC final rule, “Modernization of Oil and Gas Reporting” as discussed below. ASU 2010-03 expands the disclosures required for equity method investments, revises the definition of oil- and gas-producing activities to include nontraditional resources in reserves unless not intended to be upgraded into synthetic oil or gas, amends the definition of proved oil and gas reserves to require 12-month average pricing in estimating reserves, amends and adds definitions in the Master Glossary that is used in estimating proved oil and gas quantities and provides guidance on geographic area with respect to disclosure of information about significant reserves. ASU 2010-03 must be applied prospectively as a change in accounting principle that is inseparable from a change in accounting estimate and is effective for entities with annual reporting periods ending on or after December 31, 2009. Osage adopted ASU 2010-03 (see Supplemental Information to Consolidated Financial Statements) effective December 31, 2010.

 

F-11
 

  

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 TAXES

 

The Company followed 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 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.

 

In 2011, we had a provision for income taxes consisting primarily of federal alternative minimum tax. We did not have a provision for income taxes for 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.

 

EARNINGS (Loss) PER SHARE

 

The Company uses SFAS No. 128, “Earnings Per Share”, as codified by FASB ASC topic 260, for calculating the basic and diluted earnings (loss) per share. Basic earnings (loss) per share is computed by dividing net income (loss) attributable to common stockholders by the weighted average number of common shares outstanding during the year. In 2011, the effect of including shares attributable to the exercise of warrants would have been antidilutive and are therefore not included in the calculation of earnings per share. In 2010, common stock equivalents were excluded from the calculation as we incurred a net loss in 2010 and the effect would have been anti-dilutive.

 

2. EQUITY TRANSACTIONS

 

Cimarrona Acquisition

On April 8, 2008, we entered into the Purchase Agreement with Sunstone pursuant to which the Company acquired from Sunstone 100% of the membership interests in Cimarrona LLC, 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 cover 30,665 acres in the Middle Magdalena Valley in Colombia. The Purchase Agreement was effective as of April 1, 2008. The purchase price consisted of 2,750,000 shares of the Company’s Common stock and a warrant to purchase 1,125,000 shares of the Company’s Common stock at $1.25 per share and expiring April 8, 2013. In addition, the Company issued 50,000 shares of Common stock to a financial advisor and $22,500 to an unaffiliated individual as a finder’s fee.

 

F-12
 

  

3. GEOGRAPHICAL INFORMATION

 

The following table sets forth revenues and assets by geographical locations for the periods reported:

 

   Colombia   United States   Consolidated 
Year ending December 31, 2011               
Total Revenues  $3,462,495   $53,228   $3,515,723 
% of Total   98.5%   1.5%   100.0%
                
December 31, 2011               
Long Lived Assets  $2,062,492   $2,395,013   $4,457,505 
% of Total   46.3%   53.7%   100.0%
                
Year ending December 31, 2010               
Total Revenues   1,735,507    98,270   $1,833,777 
% of Total   94.6%   5.4%   100.0%
                
December 31, 2010               
Long Lived Assets  $2,060,021   $859,819   $2,919,840 
% of Total   70.6%   29.4%   100.0%

 

4. OIL AND GAS PROPERTIES

 

Oil and gas properties consisted of the following as of December 31, 2011 and 2010:

 

   2011   2010 
           
Properties subject to amortization  $2,215,936   $2,225,369 
Properties not subject to amortization   2,115,481    593,464 
Capitalized asset retirement costs   46,416    46,146 
           
Accumulated depreciation and depletion   (1,294,767)   (897,833)
           
Oil & Gas Properties, Net  $3,083,066   $1,967,146 

 

Depreciation and depletion expense for oil and gas properties totaled $396,934 and $340,979 in 2011 and 2010, respectively.

 

On April 21, 2011, we entered into a participation agreement (“Participation Agreement”) with Slawson Exploration Company (“Slawson”) and U.S. Energy Development Corporation (“USE”, Slawson and USE, together, the “Parties”). Pursuant to the terms of the Participation Agreement, Slawson and USE acquired 45% and 30% respectively, of our 10,000 acre Nemaha Ridge prospect in Logan County, OK for $4,875,000. In addition, the Parties shall carry Osage for 7.5% of the cost of the first three horizontal Mississippian wells. 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. Since the Participation Agreement was signed, Slawson and USE acquired 45% and 30%, respectively, of an additional 11,844 acres that we offered to them. We are continuing to acquire additional acreage in the Nemaha Ridge prospect and we will offer the additional acreage to the Parties, at our cost, subject to their acceptance. At December 31, 2011, we had 5,181 net acres (20,723 gross) leased in Logan County. In December 2011, we began drilling the Wolfe 1-29H, our first well in Logan County and in January 2012, we began drilling the Krittenbrink 2-36H, our second well in Logan County.

 

F-13
 

  

In addition to accumulating leases in Logan County, in 2011, we began to acquire leases in Pawnee County, Oklahoma, targeting the Mississippian formation and as of December 31, 2011, we had 915 net acres (1,624 gross)leased in Pawnee County. In July 2011, we entered into an agreement with B&W Exploration, Inc. (“B&W”) whereby we purchased from B&W the Pawnee County prospect 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.

 

In 2011, we also began to acquire leases in Coal County, Oklahoma, targeting the Woodford Shale formation. At December 31, 2011, we had 2,517 net (6,473 gross) acres leased in Coal County.

 

At December 31, 2011, we have leased 8,613 net acres across three counties in Oklahoma.

 

5. PROMISSORY NOTE

 

On January 24, 2011, we issued a secured promissory note to an institutional investor (“Blackrock Note”) for $500,000. 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, OK 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.

 

On April 5, 2011, we issued a secured promissory note (“Secured Promissory Note”) to E. Peter Hoffman, Jr. (“Hoffman”), an individual investor for $200,000. The Secured Promissory Note matured August 5, 2011, had a loan fee and prepaid interest of 250,000 shares of common stock, $0.0001 par value, valued at $35,000, and was secured by an assignment of the Company’s future oil and gas leases in Logan County, OK. The Company repaid the Secured Promissory Note on May 24, 2011 with the proceeds of the Participation Agreement. Hoffman owns approximately 11.8% of the Company’s shares outstanding. The Secured Promissory Note was entered into through arms-length negotiations.

 

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%. The Promissory Note matured and was paid off on October 27, 2010.

 

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.

 

F-14
 

  

The Company is not aware of any environmental claims existing as of December 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 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 year 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. Outside of the San Diego lease, the Company’s Oklahoma office and all equipment leased are under month-to-month operating leases.

 

Rental expense totaled $53,626 and $56,035 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. DILUTIVE SECURITIES

 

As of December 31, 2011 and 2010, the Company had outstanding dilutive securities, consisting entirely of warrants. Changes in warrants outstanding are as follows:

 

       Weighted Average   Average Remaining 
   Shares   Exercise Price   Contractual Life 
Balance January 1, 2010   3,612,500   $1.25    1.74 years 
Granted   -   $-      
Exercised   -   $-      
Cancelled or Expired   (1,387,500)  $1.25      
Balance December 31, 2010   2,225,000   $1.25    1.52 years 
Granted   -   $-      
Exercised   -   $-      
Cancelled or Expired   (1,100,000)  $1.25      
Balance December 31, 2011   1,125,000   $1.25    1.75 years 

 

F-15
 

 

8. INCOME TAXES

 

The total provision for income taxes consists of the following in 2011 and 2010:

 

   Year Ended December 31, 
   2011   2010 
Current Taxes:          
Federal  $57,293   $- 
State   800    - 
Foreign   -    - 
    58,093    - 
           
Deferred Taxes:          
Federal   (776)   520 
State   (158)   42 
Foreign   -    - 
           
Valuation Allowance   933    (562)
    -    - 
Totals  $58,093   $- 

 

Following is a reconciliation of the Federal statutory rate to the effective income tax rate for 2011 and 2010:

 

   2011   2010 
Computed tax provision at statutory Federal rates   34.0%   34.0%
Increase (decrease) in taxes resulting from:          
State taxes, net of Federal income tax benefit   2.5%   2.9%
Nondeductible and other expenses   0.7%   -0.3%
Federal and State true ups   -0.4%   -1.1%
State Tax Rate Change   1.5%     
Valuation Allowance   -36.0%   -35.5%
    2.3%   0.0%

 

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 .

 

Deferred tax assets and liabilities reflect the net tax effect of temporary differences between the carrying amount of assets and liabilities for financial reporting purposes and amounts used for income tax purposes. Significant components of Osage’s deferred tax assets and liabilities are as follows at December 31, 2011 and December 31, 2010 (in thousands):

 

F-16
 

 

   2011   2010 
Deferred tax liability:          
           
Net operating loss carry forward  $1,140   $2,272 
Other   1,323    1,124 
           
Valuation allowance   (2,463)   (3,396)
Net deferred tax liability   -    - 

 

The non-current portions of the deferred tax asset and the deferred tax liability accounts offset each other in the Company’s consolidated balance sheet.

 

9. MAJOR CUSTOMERS

 

During 2011 and 2010, four and three customers, respectively, accounted for all of the Company’s sales:

 

   2011   % of Total   2010   % of Total 
Hocol  $1,867,606    53.1%  $1,369,800    74.7%
Pacific   1,594,889    45.4%   365,707    19.9%
Sunoco   21,072    0.6%   98,270    5.4%
Coffeyville   32,156    0.9%   -    0.0%
Totals  $3,515,723    100.0%  $1,833,777    100.0%

 

10. 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. No income tax is applicable to the asset retirement obligation as of December 31, 2011 and 2010, 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:

 

F-17
 

  

   2011   2010 
Beginning Balance  $57,746   $55,742 
Incurred during the period   -    - 
Additions for new wells   -    - 
Accretion expense   2,204    2,004 
           
Ending Balance  $59,950   $57,746 

 

11. SUBSEQUENT EVENTS

 

Osage evaluated all transactions from December 31, 2011 through the financial statement issuance date for subsequent event disclosure.

 

12. SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

 

Petrotech Engineering, Ltd, and Reddy Petroleum Company prepared reserve estimates for the year-end reports for 2011 for the Cimarrona Property and Osage Property, respectively. Management cautions that there are many inherent uncertainties in estimating proved reserve quantities and related revenues and expenses, and in projecting future production rates and the timing and amount of development expenditures. Accordingly, these estimates will change, as future information becomes available.

 

Proved oil and gas reserves are the estimated quantities of crude oil, condensate, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e. prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual agreements, but not on escalations based upon future conditions.

 

Proved developed reserves are those reserves expected to be recovered through existing wells with existing equipment and operating methods.

 

SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies”, as codified by FASB ASC topic 932, requires disclosure of certain financial data for oil and gas operations and reserve estimates of oil and gas. This information, presented here, is intended to enable the reader to better evaluate the operations of the Company. All of the Company’s oil and gas reserves are located in the United States and Colombia.

 

The aggregate amounts of capitalized costs relating to oil and gas producing activities and the related accumulated depletion, depreciation, and amortization and valuation allowances as of December 31, 2011 and 2010 are as follows:

 

   2011   2010 
   Colombia   USA   Combined   Colombia   USA   Combined 
Proved Properties  $2,062,492   $153,444   $2,215,936   $2,071,925   $153,444   $2,225,369 
Unproved properties being amortized             -              - 
Unproved properties not being amortized   -    2,115,481    2,115,481    -    593,464    593,464 
Capitalized asset retiremet costs   13,675    32,471    46,146    13,675    32,471    46,146 
Accumulated depletion, depreciation, amortization and valuation allowances   (1,254,468)   (40,299)   (1,294,767)   (859,186)   (38,197)   (897,383)
   $821,699   $2,261,097   $3,082,796   $1,226,414   $741,182   $1,967,596 

 

F-18
 

  

Estimated quantities of proved developed and undeveloped reserves of crude oil and natural gas, as well as changes in proved developed and undeveloped reserves during the past two years are indicated below:

 

    2011 Oil (BBLs)   2011 Gas (MMCF)  
   Colombia   USA   Combined   Colombia   USA   Combined 
Proved developed and undeveloped reserves:                              
Beginning of year   272,600    126,443    399,043    59    201    260 
Revisions of previous estimates   (125,281)   (12,453)   (137,734)   306    -    306 
Improved recovery   -    -    -    -    -    - 
Purchases of Minerals in place   -    -    -    -    -    - 
Extensions and discoveries   -    -    -    -    -    - 
Production   (22,957)   (797)   (23,754)   -    -    - 
Sales of minerals in place   -    -    -    -    -    - 
End of year   124,362    113,193    237,555    365    201    566 
                               
Proved developed reserves:                              
Beginning of year   272,600    126,443    399,043    59    201    260 
End of year   124,362    113,193    237,555    365    201    566 

 

The foregoing estimates have been prepared by Petrotech Engineering, Ltd, and Reddy Petroleum Company for the Cimarrona Property and Osage County Property, respectively. Petrotech Engineering, Ltd. prepared a reserve report for Pacific for their 90.6% share of the Guaduas field. The Company utilized the results of that report to arrive at its 9.4% share of the field. Revisions in previous estimates as set forth above resulted from analysis of new information, as well as from additional production experience or from a change in economic factors. The reserve estimates are believed to be reasonable and consistent with presently known physical data concerning size and character of the reservoirs and are subject to change as additional knowledge concerning the reservoirs becomes available.

 

The Colombian reserves are attributable entirely to the Guaduas field, which we hold through our Cimarrona subsidiary, which owns 9.4% of the Guaduas field. There are no reserves attributable to partnership or minority interests at December 31, 2011 or 2010.

 

The present value of estimated future net revenues of proved developed reserves, discounted at 10%, were as follows:

 

   2011   2010 
   USA   Colombia   Combined   USA   Colombia   Combined 
Proved developed and undeveloped reserves  $5,351,306   $6,477,596   $11,828,902   $6,182,460   $9,673,389   $15,855,849 
(Present Value before income taxes)                              

 

The PV-10 has been adjusted by the Company to include estimated asset retirement obligations discounted to their present values based on a 10% annual discount rate and using the same estimated useful lives as those used in our calculation of asset retirement obligations under Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations. PV-10 is a non-GAAP financial measure; therefore, the following table reconciles our calculation of PV-10 to the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. Management believes that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies. Management believes that PV-10 is relevant and useful for evaluating the relative monetary significance of oil and natural gas properties. Further, professional analysts and sophisticated investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies’ reserves. Management also uses this pre-tax measure when assessing the potential return on investment related to oil and natural gas properties and in evaluating acquisition opportunities. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating us. PV-10 is not a measure of financial or operating performance under GAAP, nor is it intended to represent the current market value of our estimated oil and natural gas reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP.

 

F-19
 

  

The following table represents a reconciliation of our PV-10 to Standard Measure of discounted future net cash flows.

 

   At December 31, 2011 
   (unaudited) 
Present value of estimated future net revenues before asset retirement obligations  $12,936,574 
Present value of estimated asset retirement obligations, discounted at 10%   (218,201)
Present value of estimated future net revenues (PV-10)   12,718,373 
Future income taxes, discounted at 10%   (5,087,349)
Standardized measure of discounted future net cash flows  $7,631,024 

 

Depletion, depreciation and accretion per equivalent unit of production was $1.22 and $1.25 for 2011 and 2010 in the United States, respectively. In Colombia, the depletion, depreciation and accretion per equivalent unit was $2.68 and $1.16 in 2011 and 2010, respectively.

 

SFAS No. 69, “Disclosures About Oil and Gas Producing Activities”, as codified by FASB ASC Topic 932 requires certain disclosures of the costs and results of exploration and production activities and established a standardized measure of oil and gas reserves and the year-to-year changes therein.

 

In addition to the foregoing disclosures, SFAS No. 69 established a “Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves”.

 

Costs incurred, both capitalized and expensed, for oil and gas property acquisition, exploration and development for the years ended December 31, 2011 and 2010 are as follows:

 

December 31, 2011  USA   Colombia   Combined 
Property acquisition costs  $1,590,236   $-   $1,590,236 
Exploration costs   525,245    -    525,245 
Development costs   -    -    - 
Asset retirement costs   -    -    - 
                
December 31, 2010   USA    Colombia    Combined 
Property acquisition costs  $539,464   $-   $539,464 
Exploration costs   -    -    - 
Development costs   -    -    - 
Asset retirement costs   -    -    - 

 

F-20
 

  

The results of operations for oil and gas producing activities for 2011 and 2010 were as follows:

 

   2011   2010 
   USA   Colombia   Combined   USA   Colombia   Combined 
Sales  $53,228   $1,867,606   $1,920,834   $98,270   $1,369,800   $1,468,070 
Production Costs   85,286    558,011    643,297    89,806    556,434    646,240 
Exploration Costs   525,245    -    525,245    -         - 
Depletion, depreciation, amortization and valuation allowance   968    354,648    355,616    3,583    327,237    330,820 
                               
Income Tax Provision (40%)   (223,308)   381,979    158,670    1,952    194,452    196,404 
                               
Results of Operations from                              
Production activities  $(334,963)  $572,968   $238,005   $2,929   $291,677   $294,606 

 

The following information at December 31, 2011 and for 2011 and 2010, sets forth standardized measures of the discounted future net cash flows attributable to the Company’s proved oil and gas reserves.

 

Future cash inflows were computed by applying average prices of oil and gas (with consideration of price changes only to the extent provided by contractual arrangements) and using the estimated future expenditures to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions.

 

Future income tax expenses were computed by applying statutory income tax rates to the difference between pretax net cash flows relating to the Company’s proved oil and gas reserves and the tax basis of proved oil and gas properties and available operating loss and excess statutory depletion carryovers reduced by investment tax credits. Discounting the annual net cash flows at 10% illustrates the impact of timing on these future cash flows.

 

The following table presents the standardized measure of discounted estimated net cash flows relating to proved oil and gas reserves for 2011 and 2010:

 

   2011   2010 
   USA   Colombia   Combined   USA   Colombia   Combined 
Future cash inflows  $10,740,074   $13,609,561   $24,349,635   $10,818,153   $17,836,030   $28,654,183 
Furture production costs   (3,172,957)   (2,511,854)   (5,684,811)   (2,190,590)   (5,378,116)   (7,568,706)
Future development costs   (175,000)   (1,332,018)   (1,507,018)   (175,000)   (855,964)   (1,030,964)
Future abanonment costs   (92,000)   (197,400)   (289,400)   (92,000)   (159,800)   (251,800)
Future income tax expenses   (2,920,047)   (3,827,316)   (6,747,362)   (3,344,225)   (4,576,860)   (7,921,085)
                               
Future net cash flow   4,380,070    5,740,973    10,121,044    5,016,338    6,865,290    11,881,628 
10% annual discount for estimated timing of cash flows   (1,209,247)   (1,280,773)   (2,490,020)   (1,347,237)   (1,606,836)   (2,954,073)
Standardized measure of discounted future net cash flow  $3,170,823   $4,460,201   $7,631,024   $3,669,101   $5,258,454   $8,927,555 

 

F-21
 

  

The principal changes in the standardized measure of discounted future net cash flows during 2011 were as follows:

 

   2011 
   USA   Colombia   Combined 
Extensions             - 
Revisions of previous estimates               
Price changes  $1,264,430   $9,276,914   $10,541,344 
Quantity Changes   (1,060,000)   (10,987,673)   (12,047,673)
Changes in production rates, timing and other   (1,158,944)   1,948,610    789,666 
Development costs incurred             - 
Changes in estaimted future development costs   -    (476,054)   (476,054)
Purchase of Minterals in place               
Sales of oil and gas, net of production costs   32,058    (1,309,595)   (1,277,537)
Accretion of discount             - 
Net change in income taxes   424,178    749,544    1,173,723 
Net increase/ (decrease)  $(498,278)  $(798,253)  $(1,296,531)

 

F-22