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 63% and 95% of our total revenues in 2012 and 2011, respectively.
Mississippian
In 2010, we began to acquire oil and gas leases in Logan County, Oklahoma targeting the Mississippian formation. The Mississippian formation is present 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 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 40,000 barrels of oil per day. The Purchase Agreement was effective April 1, 2008.
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 plus recovery of all historical costs to develop and operate the Guaduas field. We believe Ecopetrol could become a 50% partner in the future which would reduce the cash flows generated by the field by 50%, and their partnership interest may increase thereafter to 70% based on oil production results. 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.
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. We assigned our interest in these wells in December 2012 for net proceeds of $125,000, resulting in a loss on disposal of $21,599.
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. 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. Our stock trades on the NASDAQ OTC Bulletin Board market under the ticker “OEDV”.
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, oil and gas sales from our production operations in the state of Oklahoma and pipeline revenues from our Cimarrona property in Colombia. Slawson Exploration Company (“Slawson”) is the operator of our Logan County, Oklahoma, oil and gas properties, and all of the oil and gas produced at these properties is sold by Slawson at market prices at the time of sale. Slawson is responsible for remitting our share of the oil and gas revenues to us. There is significant demand for oil and gas and there are several companies in our area that purchase oil from small oil producers.
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 2012, Slawson, Hocol, and Pacific accounted for 36.0%, 31.7%, and 31.3%, respectively, of total revenues. For 2011, Slawson, Hocol, and Pacific accounted for 0%, 53.1% and 45.4%, respectively, of total revenues.
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.
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 our 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.
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. As of December 31, 2012, we have not incurred any dismantlement and abandonment costs.
Employees
We currently have six full-time employees, including two full-time executive employees: Kim Bradford, President, Chief Executive 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.
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.
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, 2012 had an accumulated deficit of $8,074,786 and a working capital deficit of $643,843. 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.
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, by products 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 Oklahoma properties, we sold oil at $79.79 to $106.49 per barrel in 2012 compared to $82.73 to $96.89 per barrel in 2011. In our Cimarrona property in Colombia, we sold oil at $81.61 to $118.72 per barrel in 2012 compared to $82.21 to $120.22 per barrel in 2011.
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.
Item 1B. Unresolved Staff Comments
None
Item 2.
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.
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 Pinnacle Energy Services, LLC (“Pinnacle”) to prepare estimates of our oil and gas reserves in our properties in Logan 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 Pinnacle. Our Chief Geologist has over 25 years of oil and gas experience.
We retained Petrotech Engineering Ltd. (“Petrotech”) to prepare estimates of oil and gas reserves in the Cimarrona property. Management of Pacific, the operator and owner of 90.6% of the Guaduas field in Colombia, 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 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 technical person primarily responsible for audit of our reserve estimates at Pinnacle and Petrotech 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. Both Pinnacle and Petrotech are independent firms 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.
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, 2012 and 2011, Pinnacle for the properties in Logan County, Oklahoma, as of December 31, 2012, and Reddy Petroleum Company for the Hopper Property in Osage County, Oklahoma as of December 31, 2011, respectively, and are as follows:
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 $3.3 million and $6.48 million for our 9.4% share of Cimarrona property at December 31, 2012 and 2011, respectively, $14.8 million for the properties in Logan County, Oklahoma, at December 31, 2012, and $5.35 million for the Hopper Property in Osage County, Oklahoma, at December 31, 2011.
The Company’s net oil production after other working interests for 2012 and 2011 were as follows:
The Company’s average production cost per barrel is as follows:
The following summarizes the developed leasehold acreage held by the Company as of December 31, 2012 and 2011. 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.
The following summarizes the Company’s productive oil wells as of December 31, 2012 and 2011. 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.
Drilling Activity
In December 2011, the Company participated in drilling its first well in Logan County and at December 31, 2012 the Company had participated in drilling eight wells, five of which achieved production and revenues in 2012. Also as of December 31, 2012, the Company had completed four salt water disposal 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.
Item 3.
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.
Item 4. Mine Safety Disclosures
Not applicable.
PART II
Item 5.
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”. The high and low closing prices, as reported by the OTC Bulletin Board, are as follows for 2012 and 2011. The quotations reflect inter-dealer prices, without retail mark-up, mark-down or commission and may not represent actual transactions.
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.
Holders
As of March 27, 2012, there were approximately 110 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.
Item 6. Selected Financial Data
Not Applicable.
Item 7.
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 of approximately 40,000 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 plus recovery of all historical costs to develop and operate the Guaduas field, and their partnership interest may increase thereafter to 70% based on oil production results. We believe Ecopetrol could become a 50% partner in the future which would reduce the cash flows generated by the field 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 present 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 in Oklahoma since the 1940s. Beginning in 2007, the application of horizontal drilling and multi-stage hydraulic fracturing treatments have demonstrated the potential for extracting significant additional quantities of oil and natural gas from the formation.
On April 21, 2011, we entered into a participation agreement (the “Participation Agreement”) with Slawson Exploration Company (“Slawson”) and 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, Oklahoma for $4,875,000. In addition, Slawson and USE carried 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 provided up to 17.5% of the total well costs. After the first three wells, the Company is responsible for up to 25% of the total well costs. Revenue from wells drilled pursuant to the Participation Agreement 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. The Participation Agreement states that Osage will deliver acreage in the Nemaha Ridge Prospect to the Parties at a net Revenue Interest (“NRI”) of 78% unless Osage acquires the acreage at an NRI lower than 78%, in which case, the acreage will be delivered at the NRI acquired by Osage. Where Osage acquires leases with an NRI in excess of 78%, it has provided its management and consultants an overriding royalty interest (“ORRI”) equal to the difference between the NRI and 78%. At December 31, 2012, the Company had 7,797 net acres (47,627 gross) leased in Logan County. In December 2011, the Company participated in drilling its first well in Logan County and at December 31, 2012 the Company had participated in drilling eight wells, five of which achieved production and revenues in 2012. Also as of December 31, 2012, the Company had completed four salt water disposal wells.
In 2011, the Company began to acquire leases in Pawnee County, Oklahoma, targeting the Mississippian formation. In July 2011, we purchased from B&W Exploration, Inc. (“B&W”) the Pawnee County prospect targeting the Mississippian, for $8,500. In addition, B&W is also entitled to an overriding royalty interest on the leases acquired and a 12.5% carry on the first $200,000 of lease bonus paid in the form of an assignment of 12.5% of the leases acquired. As of December 31, 2012, the Company had 3,446 net acres (4,925 gross) leased in Pawnee County. As of December 31, 2012, none of these leases have been assigned to B&W.
In 2011, we also began to acquire leases in Coal County, Oklahoma, targeting the oily Woodford Shale formation. The oily Woodford Shale formation is located mainly in southeastern Oklahoma in the Arkoma Basin. The oily Woodford shale lies directly under the Mississippian and started as a vertical play, but horizontal drilling techniques and multi-stage fracturing technology have been used in the Woodford in recent years with much success. At December 31, 2012, we had 4,253 net (9,509 gross) acres leased in Coal County.
At December 31, 2012, we have leased 62,061 gross (15,496 net) acres across three counties in Oklahoma as follows:
The Company has an accumulated deficit of $8,074,786 and a working capital deficit of $643,843 at December 31, 2012. In 2011, we recognized a one-time gain of $3,109,646 from assignment of leases in Logan County, Oklahoma. Our operating plans require additional funds that may take the form of debt or equity financings. There can be no assurance that any additional funds will be available. Our ability to continue as a going concern is in substantial doubt and is dependent upon achieving a profitable level of operations and obtaining additional financing.
We anticipate we will need to raise at least $10,000,000 to sustain operations over the next 12 months, with the majority of the capital being used to drill additional wells in Logan County, Oklahoma. At present, the revenues generated from the Cimarrona and Logan County properties are only sufficient to cover field operating expenses and a portion of our overhead. We have undertaken steps as part of a plan to improve operations with the goal of sustaining our operations for the next 12 months and beyond. These steps include (a) assigning a portion of our oil and gas leases in Logan County, Oklahoma (b) participating in drilling of wells in Logan County, Oklahoma within the next 12 months, (c) controlling overhead and expenses and (d) raising additional capital and/or obtaining financing. There is no assurance we will successfully accomplish these steps and it is uncertain we will achieve profitable operations and/or obtain additional financing. There can be no assurance any additional financings will be available to us on satisfactory terms and conditions, if at all. In the event we are unable to continue as a going concern, we may elect or be required to seek protection from our creditors by filing a voluntary petition in bankruptcy or may be subject to an involuntary petition in bankruptcy. To date, management has not considered this alternative, nor does management view it as a likely occurrence.
On April 17, 2012, we issued a secured promissory note (“Secured Promissory Note”) to Boothbay Royalty Co. (Boothbay) for $2,500,000. On April 27, 2012, we entered into a $10,000,000 senior secured note purchase agreement (“Note Purchase Agreement”) with Apollo Investment Corporation (“Apollo”) (see Note 6 - Debt, in the accompanying consolidated financial statements). We anticipate that we will draw down the full $10,000,000 available to us under the Note Purchase Agreement during the next 12 months to support the drilling in Logan County, as well as the other counties in Oklahoma. We are currently in negotiations with Apollo with respect to an expanded senior secured facility.
Results of Operations
Year ended December 31, 2012 compared to year ended December 31, 2011
Oil Sales
Oil sales were $3,973,666, in 2012, an increase of $2,052,832, or 106.9%, compared to $1,920,834 in 2011. The increase in oil sales is mostly due to our new wells in Logan County, Oklahoma. In the United States, we sold 22,146 barrels (“BBLs”) in 2012 at an average gross price of $94.13 per barrel, compared to 797 BBLs in 2011 at an average price of $88.60 per barrel. In Colombia, we sold 19,000 barrels in both 2012 and 2011, at an average price per barrel of $105.98 in 2012 compared to $101.86 in 2011.
Pipeline Sales
Pipeline sales were $1,912,941 in 2012, an increase of $318,052, or 19.9%, compared to $1,594,889 in 2011. In 2011, the pipeline transported 10.13 million BBLs (our share was approximately 0.95 million BBLs) compared to 9.17 million BBls (our share was approximately 0.86 million BBLs) in 2011. Revenue per barrel transported was $2.01 in the year ended December 31, 2012 compared to $1.81 in the year ended December 31, 2011.
Natural Gas Sales
Natural gas sales were $233,417 for the year ended December 31, 2012 compared to $0 for the year ended December 31, 2011. All of our natural gas sales are from the well production in Logan County, Oklahoma. Natural gas production is measured in a 1,000 cubic foot unit referred to as a “Mcf.”
Total Revenues
Total revenues were $6,120,024, an increase of $2,604,301 or 74.1% for the year ended December 31, 2012 compared to $3,515,723 for the year ended December 31, 2011. Oil sales accounted for 64.9% and 54.6% of total revenues in the 2012 and 2011 periods, respectively.
Production
Oil production, net of royalties, was 39,683 BBLs, an increase of 20,522 BBLs, or 107.1% for the year ended December 31, 2012 compared to 19,162 BBLs for the year ended December 31, 2011, due to production increases in the U.S. U.S. production accounted for 55.6% and 4.2% of total production for the years ended December 31, 2012 and 2011, respectively.
Natural gas production was 62,131 Mcf for the year ended December 31, 2012. Gas production began in the first quarter of 2012 in our Logan County properties, and there was no production of natural gas during 2011.
Operating Costs and Expenses
Operating Expenses
Our operating expenses in 2012 were $1,812,725, an increase of $744,638, or 69.7% compared to $1,086,087 in 2011, due primarily to an increase in operating costs in Logan County, Oklahoma. Operating expenses as a percentage of total revenues declined to 29.6% in 2012 from 30.4% in 2011, as the percentage increase in revenues was greater than the percentage increase in operating costs as new wells came into production. Operating costs as a percentage of revenues also declined as a result of the increased percentage of U.S. production, to 55.6% in 2012 from 4.2% in 2011 as average Production Cost/BOE in the U.S. for 2012 was $7.26 compared to the average cost in Colombia of $41.04. Our average total Production Cost/BOE for the year ended December 31, 2012 was $19.45.
General and Administrative Expenses
General and administrative expenses in 2012 were $2,716,233, an increase of $761,947, or 39.0% compared to $1,954,286 in 2011. Stock-based compensation expense was $896,694 and $267,600 in 2012 and 2011, respectively. The increase in stock-based compensation expense of $629,094 for the year ended December 31, 2012 related both to an increase in stock granted and to an increase in the stock price at the time of issuance. The majority of shares were immediately vested. The remaining increase of $132,853 is due primarily to a $42,882 increase in legal and professional services, a $29,310 increase in insurance, a $13,125 increase in office expenses and a $8,914 increase in computer expenses. General and administrative expenses as a percentage of total revenues decreased to 44.4% in 2012 from 55.6% in 2011, due to the 74.1% increase in revenues.
Equity Tax
Division de Impuestosy Actuanas Nacionales (“DIAN”), the Colombian tax authorities, levies a tax based on the equity value of Cimarrona. The equity tax for 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.
In 2010, the Company was notified by DIAN that it owed $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 had 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 indicated we owed for the 2003 tax year. In January 2013 we concluded negotiations with DIAN with respect to the ultimate liability for the 2003 tax year. DIAN waived certain penalties and interest in the amount of $548,092. We paid the agreed final liability to DIAN in January 2013, using the proceeds of an unsecured Colombian banking facility and are awaiting confirmation that the 2003 tax year is fully settled. We will recognize the benefit upon receipt of such confirmation.
Depreciation, depletion and accretion
Depreciation, depletion and accretion were $568,777 for the year ended December 31, 2012 and $429,689 for the year ended December 31, 2011, an increase of $139,088 or 32.4%. Our depletion expense will increase in the future to the extent we are successful in our well production in Oklahoma.
Income / (Loss) from Operations
Income from operations was $869,504 in 2012 compared to a loss from operations of $386,403 in 2011. The improvement in operating results of $1,255,907 was due to the increase in revenues of $2,604,301 for the year ended December 31, 2012 compared to the year ended December 31, 2011, partially offset by the $1,348,394 increase in operating costs and expenses during the same period.
Interest Expense
Interest expense was $1,390,277 for the year ended December 31, 2012 compared to $137,204 for the year ended December 31, 2011, an increase of $1,253,073. The increase in interest expense during the 2012 period was primarily due to deferred financing fees amortization, interest expense, standby fees and debt discount amortization in connection with the Note Purchase Agreement and Secured Promissory Note. Interest expense for the 2011 period is for the Blackrock Promissory Note issued in January 2011 and repaid in May 2011, and the Hoffman Note issued in April 2011 and repaid in May 2011. In the year ended December 31, 2012, cash interest expense amounted to $538,889. The remaining non-cash interest expense of $851,388 consisted primarily of deferred financing fees of $734,976 and debt discount amortization of $114,596.
Gain from Assignment of Leases
We recognized a gain from assignment of leases of $0 in 2012 compared to $3,109,646 in 2011. 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 $0 in 2012 compared to $58,893 in 2011. 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 (Loss) / Income
Net loss was $516,706 in 2012 compared to a net income of $2,535,599 in 2011. The improvement in operating income in 2012 of $1,255,907 compared to 2011 was offset by the $1,253,073 increase in interest expense in 2012 and the $3,109,646 gain from assignment of leases in 2011.
Foreign Currency Translation
Foreign currency translation loss was $21,460 in 2012 compared to a gain of $7,276 in 2011. The Colombian Peso to Dollar Exchange Rate averaged 1,797 and 1,848 in 2012 and 2011, respectively. The Colombian Peso to Dollar Exchange Rate was 1,805 and 1,935 at December 31, 2012 and December 31, 2011, respectively.
Comprehensive Income/(Loss)
Comprehensive loss was $538,166 for the year ended December 31, 2012 compared to a comprehensive income of $2,542,875 for the year ended December 31, 2011. Comprehensive income decreased by $3,081,041 due to the $3,052,305 decrease in net income to a loss in the 2012 period compared to the 2011 period and the $28,736 decrease in foreign currency translation to a loss in the 2012 period compared to a gain in the 2011 period.
Income/(Loss) per Share
Basic and diluted loss per share was $0.01 in 2012 compared to an income per share of $0.05 in 2011.
Liquidity and Capital Resources
We had a working capital deficit of $643,843 at December 31, 2012, compared to working capital of $1,061,190 at December 31, 2011. Working capital at December 31, 2012 consisted primarily of deferred financing costs of $2,924,472, $486,205 of cash and equivalents and $486,112 of accounts receivable offset by $3,000,000 of notes payable, $1,328,652 of accrued expenses and $236,977 of accounts payable. Working capital at December 31, 2011 consisted primarily of $1,904,023 of cash and equivalents and $358,344 of accounts receivable offset by $876,545 of accrued expenses and $323,699 of accounts payable.
Net cash provided by operating activities was $1,834,606 in 2012 compared to $57,649 in 2011. The major components of net cash provided by operating activities in 2012 were the $568,777 provision for depreciation, depletion and the amortization of deferred financing costs of $734,796, shares issued for services of $448,583 and warrants issued for services of $448,111, offset by the $516,706 net loss and the increase in accounts receivable of $363,548. 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.
Net cash used by investing activities was $7,970,569 in 2012 compared to net cash provided by investing activities of $1,559,853 in 2011. Net cash used by investing activities in 2012 consisted primarily of $12,781,375 investment in oil and gas properties, partially offset by $4,686,610 net proceeds from assignment of leases. 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 provided by financing activities was $4,831,308 and $0 in 2012 and 2011, respectively. Net cash provided in 2012 consisted primarily of $5,500,000 of borrowing on secured promissory notes, partially offset by payment of $670,692 of deferred financing costs. 2011 consisted of $700,000 of borrowing on promissory notes offset by $700,000 of repayment of those promissory notes.
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.
Slawson is the operator in our Logan County, Oklahoma properties. 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.
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 the majority our oil and gas production to Slawson 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 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 field-by-field basis. As of December 31, 2012 and 2011, 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.
In accordance with FASB ASC Topic 410, “Accounting for Asset Retirement Obligations”, 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 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.
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 7A.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
We are subject to changes in the price of oil and exchange rates of the Colombian Peso, which are out of our control. At our Oklahoma Properties, we sold oil at $79.79 to $106.49 per barrel in 2012 compared to $82.73 to $96.89 per barrel in 2011. In our Cimarrona property in Colombia, we sold oil at $81.61 to $116.63 per barrel in 2012 compared to $82.21 to $120.22 per barrel in 2011.
The Colombian Peso to Dollar Exchange Rate averaged approximately 1,797 and 1,848 in 2012 and 2011, respectively. The Colombian Peso to Dollar Exchange Rate was 1,765 and 1,935 at December 31, 2012 and December 31, 2011, respectively.
We also have exposure to interest rate changes, as the interest on one of our debt facilities is tied to the London Interbank Overnight Rate (“Libor”).
Item 8.
Item 8. Financial Statements and Supplementary Data
Our consolidated financial statements as of December 31, 2012 and for the fiscal year then ended were audited by MaloneBailey, LLP, an independent registered accounting firm. Our consolidated financial statements as of December 31, 2011 and for the fiscal year then ended were audited by GKM, LLP, an independent registered public accounting firm. These consolidated financial statements 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.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
In September 2012 we dismissed GKM, LLP and appointed MaloneBailey, LLP as our independent public accounting firm for the 2012 fiscal year. There were no disagreements with either independent public accounting firm on accounting or financial disclosure.
Item 9A.
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, 2012, utilizing a top-down, risk based approach described in SEC Release No. 34-55929 as suitable for smaller public companies. Based on this assessment, management determined that the Company’s internal control over financial reporting as of December 31, 2012 was not effective. Based on this assessment, management has determined that, as of December 31, 2012, there were material weaknesses in our internal control over financial reporting. The material weaknesses identified during management’s assessment were the lack of independent oversight by an audit committee of independent members of the Board of Directors and lack of controls over depletion calculations. 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.
(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, 2012 that have materially affected, or are reasonable likely to materially affect, the Company’s internal control over financial reporting.
Item 9B.
Item 9B. Other Information
None
Item 10.
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, Chairman
February 2007
Greg Franklin
Chief Geologist, Director
May 2005
Norman Dowling
Chief Financial Officer
N/A
A list of current executive officers and directors appears above. The directors of the Company are elected annually by the stockholders. The executive 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 2007. In September 2008, Mr. Bradford once again became our Chief Financial Officer through January 2013. 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.
Norman Dowling: Mr. Dowling has been our Chief Financial Officer since January 2013, devoting approximately one third of his time to the Company. Since 2009, Mr. Dowling has been engaged as a consultant to various companies, providing consulting services primarily in the retail and internet sectors. Mr. Dowling has provided consulting services to the Company since October 2012. From 2004 to 2008 Mr. Dowling served as Executive Vice President and Chief Financial Officer of The Active Network, Inc. (“Active”) from 2004 through 2008, during which time Active completed 23 acquisitions and three private equity rounds raising over $165 million. From 1999 to 2004, Mr. Dowling served as Vice President Finance, at PETCO Animal Supplies, Inc. (“PETCO”) during which time PETCO was taken private through a leveraged recapitalization and re-emerged as a public company through an initial public offering. Mr. Dowling also served as Chief Financial Officer of Factory 2U Stores, Inc. in 2004 and CinemaStar Luxury Theatres, Inc. from 1997 to 1999. In addition to a number of other senior financial positions, Mr. Dowling’s experience includes six years with Ernst & Young in audit assurance and management consultancy roles. Mr. Dowling holds a Bachelor of Commerce degree from University College Dublin, Ireland.
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, 2012.
Audit Committee
We do not have an Audit Committee, as our BOD during 2012 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 Board of Directors 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.
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 Board of Directors will review all forms of compensation provided to our executive officers, directors, consultants and employees including stock compensation and loans.
Item 11.
Item 11. Executive Compensation
Executive Officers
Our current executive officers are as follows:
Name
Age
Position
Kim Bradford
President, Chief Executive Officer
Greg Franklin
Chief Geologist
Norman Dowling
Chief Financial Officer
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, Norman Dowling, who serves as 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:
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 agreement 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.
On January 21, 2013, the Company entered into a consulting agreement with Norman Dowling to serve as Chief Financial Officer in a part-time capacity.
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
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The following table shows information as of March 27, 2013 with respect to each beneficial owner of more than five percent of the Company’s Common stock:
The percentage ownership is based on 49,494,675 shares outstanding at March 27, 2013
[1] Information is derived from Schedule 13D filed by Mustang Capital Venture, LLC on March 16, 2009.
[2] Information is derived from Schedule 13D filed by Sunstone Corporation on February 1, 2013. Includes 1,250,000 warrants to purchase shares of common stock exercisable within 60 days which expire on April 8, 2013.
[3] Information is derived from Schedule 13D Amendment #4 filed by Mr. Hoffman, Jr. on November 14, 2012.
The following table shows information as of March 27, 2013 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:
The percentage ownership is based on 49,494,675 shares outstanding at March 27, 2013.
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, 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, 2012, there are outstanding notes receivable for $95,000, representing 3,800,000 shares. The Company is currently attempting to collect the notes receivable.
Item 13.
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 and Chief Executive Officer and Greg Franklin, our Chief Geologist. 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 Board of Directors be independent.
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.
Item 14. Principal Accounting Fees and Services
Selection of our Independent Registered Public Accounting Firm is made by the BOD. MaloneBailey, LLP has been selected as our Independent Registered Public Accounting Firm for the current fiscal year. All audit and non-audit services provided by MaloneBailey 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 MaloneBailey 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 MaloneBailey LLP are compatible with maintaining its independence and has determined that the nature and substance of the limited non-audit services have not impaired MaloneBailey 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 2012 and 2011.
TAX FEES
Our auditors did not bill us for any tax services during 2012 and 2011.
ALL OTHER FEES
Our auditors did not bill us for any other services during 2012 and 2011.
Part IV
Item 15.
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)
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, 2011 (16)
10.24.1
Pinnacle Energy LLC reserve report for the Logan property as of December 31, 2012 (*)
10.24.2
Consent of Pinnacle Energy LLC(*)
10.25
Petrotech Engineering Ltd. reserve report for the Cimarrona property as of December 31, 2011 (16)
10.25.1
Petrotech Engineering Ltd. reserve report for the Cimarrona property as of December 31, 2012 (*)
10.25.2
Consent of Petrotech Engineering Ltd.(*)
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)
(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
(16) Incorporated by reference to Osage’s Form 10-K filed March 23, 2012
(*) Filed with this Form 10K
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: April 2, 2013
BY: /S/ NORMAN DOWLING
Norman Dowling
Chief Financial Officer
Dated: April 2, 2013
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
/s/ KIM BRADFORD
President, Chief Executive Officer, and Chairman
April 2, 2013
Kim Bradford
(Principal Executive Officer)
/s/ GREG FRANKLIN
April 2, 2013
Greg Franklin
Chief Geologist and Director
/s/ NORMAN DOWLING
Chief Financial Officer
April 2, 2013
Norman Dowling
(Principal Financial Officer)
OSAGE EXPLORATION AND DEVELOPMENT, INC.
Set forth below are the following consolidated financial statements for our company for the years ended December 31, 2012 and 2011:
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders
Osage Exploration and Development, Inc. and Subsidiaries
San Diego, CA
We have audited the accompanying consolidated balance sheet of Osage Exploration and Development, Inc. and subsidiaries (collectively “the Company”) as of December 31, 2012, and the related consolidated statements of operations and other comprehensive income (loss), stockholders’ equity, and cash flows for the year then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform an audit 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 its internal control over financial reporting. Our audit 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. Accordingly, we express no such opinion. 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 audit provides 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, 2012 and the results of their operations and their cash flows for the year then ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.
The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the consolidated financial statements, the Company has a working capital deficit and an accumulated deficit as of December 31, 2012 which raises substantial doubt about its ability to continue as a going concern. Management’s plans regarding those matters are described in Note 2. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.
/s/ MaloneBailey, LLP
www.malonebailey.com
Houston, Texas
April 2, 2013
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 sheet of Osage Exploration and Development, Inc. (Company), as of December 31, 2011, and the related consolidated statement of operations, stockholders’ equity, and cash flows for the year then ended. 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 audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit 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 audit 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 audit 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 year then ended, 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 2 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 2 to the consolidated financial statements. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.
/s/ Goldman, Kurland and Mohidin LLP
Goldman, Kurland and Mohidin LLP
Encino, California
March 21, 2012
OSAGE EXPLORATION AND DEVELOPMENT, INC.
CONSOLIDATED BALANCE SHEETS
As of Ended December 31, 2012 and December 31, 2011
The accompanying notes are an integral part of these consolidated financial statements.
OSAGE EXPLORATION AND DEVELOPMENT, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS AND OTHER COMPREHENSIVE INCOME (LOSS)
For Years Ended December 31, 2012 and 2011
The accompanying notes are an integral part of these consolidated financial statements.
OSAGE EXPLORATION AND DEVELOPMENT, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For Years Ended December 31, 2012 and December 31, 2011
The accompanying notes are an integral part of these consolidated financial statements.
OSAGE EXPLORATION AND DEVELOPMENT, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
For Years Ended December 31, 2012 and December 31, 2011
The accompanying notes are an integral part of these consolidated financial statements.
OSAGE EXPLORATION AND DEVELOPMENT, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 sale of oil, gas and natural gas liquids. The Company’s production activities are located in the State of Oklahoma and the country of Colombia. The principal executive offices of the Company are at 2445 Fifth Avenue, Suite 310, San Diego, CA 92101. Osage was organized on September 9, 2004 as Osage Energy Company, LLC, (“Osage LLC”) an Oklahoma limited liability company. On April 24, 2006 we merged with a non-reporting, Nevada corporation trading on the pink sheets, Kachina Gold Corporation, which was the entity which survived the merger, through the issuance of 10,000,000 shares of our common stock. The merger was accounted for as a recapitalization of Osage LLC rather than as a business combination.
The Nevada non-reporting corporation was incorporated under the laws of Canada on February 24, 2003 as First Mediterranean Gold Resources, Inc. (“FMGR”). The domicile of FMGR was changed to the State of Nevada on May 11, 2004. On May 24, 2004, the name of FMGR was changed to Advantage Opportunity Corp (“AOC”). On March 4, 2005, AOC 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, Inc. On July 2, 2007, Osage Energy Corporation, Inc. 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”.
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. These reclassifications have no affect on the reported results in 2012 or 2011.
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 12: 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.
DEFERRED FINANCING COSTS
The Company incurred deferred financing costs in connection with the Note Purchase Agreement (see Note 6), which represented the fair value of warrants, placement fees and legal fees. Deferred financing costs of $3,659,448 are being amortized over the term of the Note Purchase Agreement on a straight-line basis.
During the year ended December 31, 2012, the Company made payments of $670,692 for deferred financing fees in connection with the Note Purchase Agreement.
Deferred financing costs at December 31, 2012 were $2,924,472. Amortization of deferred financing costs was $734,976 for the year ended December 31, 2012. There were no deferred financing fees incurred during the year ended December 31, 2011.
FAIR VALUE OF FINANCIAL INSTRUMENTS
As of December 31, 2012 and December 31, 2011, the fair value of cash, accounts receivable and accounts payable approximate carrying values because of the short-term maturity of these instruments.
Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 820, “Fair Value Measurements and Disclosures,” requires disclosure of the fair value of financial instruments held by the Company. ASC Topic 825, “Financial Instruments,” defines fair value, and establishes a three-level valuation hierarchy for disclosures of fair value measurement that enhances disclosure requirements for fair value measures. The carrying amounts reported in the consolidated balance sheets for receivables and current liabilities each qualify as financial instruments and are a reasonable estimate of their fair value because of the short period of time between the origination of such instruments and their expected realization and their current market rate of interest.
The three levels of valuation hierarchy are defined as follows:
● Level 1 inputs to the valuation methodology are quoted prices for identical assets or liabilities in active markets.
● Level 2 inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, quoted prices for identical or similar assets in inactive markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.
● Level 3 inputs to the valuation methodology us one or more unobservable inputs which are significant to the fair value measurement.
The Company analyzes all financial instruments with features of both liabilities and equity under ASC Topic 480, “Distinguishing Liabilities from Equity,” and ASC Topic 815, “Derivatives and Hedging.”
As of December 31, 2012 and December 31, 2011, the Company did not identify any assets and liabilities that are required to be presented on the balance sheet at fair value.
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 2012 and 2011. At December 31, 2012, the Company had $82,020 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 banks exceeding the FDIC insured levels is remote. The Company generated substantially all of its revenues from three customers in 2012 and two customers in 2011. (See “Accounts Receivable and Allowance for Doubtful Accounts” below).
RESTRICTED CASH
In connection with the Boothbay Secured Promissory Note (see Note 6) the Company is required to deposit certain royalty interests of Boothbay’s into joint accounts held by the Company for the benefit of Boothbay. These royalty interests at December 31, 2012 were $102,467, compared to $0 at December 31, 2011. The Company has also pledged $55,000 for certain bonds and sureties.
ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS
The Company recognizes accounts receivable when sales are invoiced and regularly reviews accounts receivable for doubtful accounts.
In the U.S., the Company currently sells substantially all of its oil and gas production to one customer, Slawson Exploration Company (“Slawson”). 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, 2012 and 2011. 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 were the operators of this property and sold our interest in the fourth quarter of 2012.
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 field-by-field basis. As of December 31, 2012 and 2011, 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, 2012 and 2011.
The Company follows the “successful efforts” method of accounting for its oil and gas exploration and development activities, as set forth in 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.
ASSET RETIREMENT OBLIGATIONS
In accordance with 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 as interest 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
The Company follows the guidance provided under FASB ASC Topic 360 (“ASC 360”), “Accounting for the Impairment or Disposal of Long-Lived Assets”, which addresses financial accounting and reporting for the impairment or disposal of long-lived assets. The Company periodically evaluates the carrying value of long-lived assets to be held and used in accordance with ASC 360. ASC 360 requires impairment losses to be recorded on long-lived assets used in operations when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying amounts. In that event, a loss is recognized based on the amount by which the carrying amount exceeds the fair market value of the long-lived assets. Loss on long-lived assets to be disposed of is determined in a similar manner, except that fair market values are reduced for the cost of disposal. During the years ended December 31, 2012 and 2011, the Company did not record impairment charges related to its long-lived assets.
REVENUE RECOGNITION
Revenues from the sale of crude oil, natural gas, and natural gas liquids are recognized when the product is delivered at a fixed or determinable price, title has transferred, collectability is reasonably assured and evidenced by a contract. The Company follows the sales method of accounting for its oil and natural gas revenue, so it recognizes revenue on all crude oil, natural gas, and natural gas liquids sold to purchasers, regardless of whether the sales are proportionate to its ownership in the property. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves. The Company had no imbalance positions at December 31, 2012 or 2011, and no receivables, payables or unearned revenue are recorded.
STOCK BASED COMPENSATION
The Company accounts for stock-based compensation to employees in accordance with FASB ASC 718. Stock-based compensation to employees is measured at the grant date, based on the fair value of the award, and is recognized as expense over the requisite vesting period. The majority of stock-based compensation to employees and to other than employees has immediate vesting and thus was expensed at the time of grant. The Company accounts for stock-based compensation to other than employees in accordance with FASB ASC 505-50. Equity instruments issued to other than employees are valued at the earlier of a commitment date or upon completion of the services, based on the fair value of the equity instruments, and is recognized as expense over the service period or immediately if the award has immediate vesting. The Company estimates the fair value of stock-based payments using the Black-Scholes option-pricing model for common stock options and warrants and the closing price of the Company’s common stock for common share issuances.
INCOME TAXES
The Company follows FASB ASC Topic 740 (“ASC 740”), “Accounting for Uncertainty in Income Taxes.” As a result of the implementation of ASC 740, the Company made a comprehensive review of its portfolio of tax positions in accordance with recognition standards established by ASC 740. The Company recognized no material adjustments to liabilities or stockholders equity as a result of this review. When tax returns are filed, it is likely some positions taken would be sustained upon examination by the taxing authorities, while others are subject to uncertainty about the merits of the position taken or the amount of the position that would be ultimately sustained. The benefit of a tax position is recognized in the financial statements in the period during which, based on all available evidence, management believes it is more likely than not the position will be sustained upon examination, including the resolution of appeals or litigation processes, if any. Tax positions taken are not offset or aggregated with other positions. Tax positions that meet the more-likely-than-not recognition threshold are measured as the largest amount of tax benefit that is more than 50% likely of being realized upon settlement with the applicable taxing authority. The portion of the benefits associated with tax positions taken that exceeds the amount measured as described above is reflected as a liability for unrecognized tax benefits in the accompanying balance sheets along with any associated interest and penalties that would be payable to the taxing authorities upon examination. Interest associated with unrecognized tax benefits are classified as interest expense and penalties are classified in selling, general and administrative expenses in the Consolidated Statement of Operations. Due to a history of operating losses, the Company records a full valuation allowance against its net deferred tax assets.
At December 31, 2012, the Company had Federal and state net operating loss carry forwards of approximately $7.2 million which expire at various dates through 2032.
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
In accordance with FASB ASC Topic 260 “Earnings Per Share,” the Company’s basic net income/loss per share of common stock is calculated by dividing net income/loss by the weighted-average number of shares of common stock outstanding for the period. The diluted net income/loss per share of common stock is computed by dividing the net income/loss using the weighted-average number of common shares including potential dilutive common shares outstanding during the period. Potential common shares are excluded from the computation of diluted net loss per share if anti-dilutive. Potential common shares consisted of 3,071,843 and 1,125,000 warrants to purchase common stock at December 31, 2012 and 2011, respectively.
The following table shows the computation of basic and diluted net income (loss) per share for the years ended December 31, 2012 and 2011:
3,071,843 and 1,125,000 warrants to purchase common stock at December 31, 2012 and December 31, 2011, respectively, were excluded from the computation as their effect would have been anti-dilutive. (See Note 3).
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
The Company does not expect the adoption of any recently issued accounting pronouncements to have a material impact on the consolidated financial statements.
2. GOING CONCERN
The Company has a working capital deficit of $643,843 and an accumulated deficit of $8,074,786 at December 31, 2012 and recorded a net loss in 2012. 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 also recorded a net loss for 2011. The Company’s operating plans require additional funds which may take the form of debt or equity financings. These conditions raise substantial doubt as to the Company’s ability to continue as a going concern. The Company’s ability to continue as a going concern is in substantial doubt and is dependent upon achieving profitable operations and obtaining additional financing. There is no assurance additional funds will be available.
Management of the Company has undertaken steps as part of a plan to improve operations with the goal of sustaining our operations for the next 12 months and beyond. These steps include (a) assigning a portion of our oil and gas leases in Logan County, Oklahoma (b) participating in drilling of wells in Logan County, Oklahoma within the next 12 months, (c) controlling overhead and expenses and (d) raising additional equity and/or debt. There is no assurance the Company can accomplish these steps and it is uncertain the Company will achieve profitable operations and obtain additional financing. There is no assurance additional financings will be available to the Company on satisfactory terms and conditions, if at all. If we are unable to continue as a going concern, we may elect or be required to seek protection from our creditors by filing a voluntary petition in bankruptcy or may be subject to an involuntary petition in bankruptcy. To date, management has not considered this alternative, nor does management view it as a likely occurrence.
These consolidated financial statements do not give effect to any adjustments which would be necessary should the Company be unable to continue as a going concern and therefore be required to realize its assets and discharge its liabilities in other than the normal course of business and at amounts different from those reflected in the accompanying unaudited consolidated financial statements.
3. 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.
Common Stock
On January 27, 2012, the Company issued 90,000 shares of common stock at $41,400 or $0.46 per share, to a consultant as compensation for services rendered March through August 2012.
On April 16, 2012, the Company issued 20,000 shares of common stock at $23,000 or $1.15 per share, to a consultant as compensation for services rendered.
On April 17, 2012, in connection with the Secured Promissory Note, we issued to Boothbay 400,000 shares of common stock at $385,656, the relative fair value (see Note 6 - Debt).
On August 1, 2012, in connection with a three-year employment agreement, we agreed to issue 150,000 shares of common stock at future dates as specified in the agreement. We will issue 50,000 shares on each of the first, second, and third anniversaries of the execution of the agreement subject to other terms and conditions of the agreement. The 150,000 shares were valued at $177,000, or $1.18 per share, and will be expensed over the three years of the employment agreement. We recognized $24,583 of expenses as of December 31, 2012.
On August 26, 2012, a consultant who had previously been issued a warrant to purchase common stock exercised the warrant and purchased 200,000 shares of common stock for $2,000. (see “Warrants” below)
On November 27, 2012, the Company issued 500,000 shares of common stock at $350,000 or $0.70 per share, to a consultant as compensation for services rendered.
Warrants
On April 16, 2012, we issued a warrant to purchase 200,000 shares of common stock, exercisable at $0.01 per share, with a Black-Scholes value of $229,056 and a term of 2 years, to a consultant as compensation for services rendered. Variables used in the valuation include (1) discount rate of 0.27%, (2) expected life of 2 years, (3) expected volatility of 244.0% and (4) zero expected dividends. On August 24, 2012, the consultant exercised the warrant and purchased the 200,000 shares of common stock for $2,000.
On April 20, 2012, we issued a warrant to purchase 200,000 shares of common stock, exercisable at $0.01 per share, with a Black-Scholes value of $219,055 and a term of 2 years, to a consultant as compensation for services rendered. Variables used in the valuation include (1) discount rate of 0.29%, (2) expected life of 2 years, (3) expected volatility of 243.0% and (4) zero expected dividends.
On April 27, 2012, in connection with the Note Purchase Agreement, we issued a warrant to the investor to purchase 1,496,843 shares of common stock, exercisable at $0.01 per share, with a Black-Scholes value of $2,483,952 and a term of 5 years. Variables used in the valuation include (1) discount rate of 0.82%, (2) expected life of 5 years, (3) expected volatity of 245.0% and (4) zero expected dividends. At closing of the Note Purchase Agreement, we issued a warrant to the placement agent to purchase 250,000 shares of common stock, $0.0001 par value, exercisable at $0.01 per share, with a Black-Scholes value of $413,690 and a term of 2 years. Variables used in the valuation include (1) discount rate of 0.26%, (2) expected life of 2 years, (3) expected volatility of 242.0% and (4) zero expected dividends. (see Note 6 - Debt).
On December 27, 2012, we issued a warrant to purchase 100,000 shares of common stock, exercisable at $0.01 per share, with a Black-Scholes value of $89,952 and a term of 5 years, to the placement agent for the Note Purchase Agreement and amended the term of the warrant granted on April 27, 2012 from two to five years, with a Black-Scholes value of $1,161. Variables used in the valuation include (1) discount rate of 0.72%, (2) expected life of 5 years, (3) expected volatility of 242.0% and (4) zero expected dividends.
As of December 31, 2012 and 2011, the Company had outstanding dilutive securities, consisting entirely of warrants. Changes in warrants outstanding are as follows:
The intrinsic value of the warrants outstanding as of December 31, 2012 was $1,801,822.
4. SEGMENT AND GEOGRAPHICAL INFORMATION
The Company operates in two segments and has activities in two geographical regions. The Oil / Gas segment engages primarily in the acquisition, development, production and sale of oil, gas and natural gas liquids. The Pipeline segment engages primarily in the transport of oil.
The following tables set forth revenues, income and assets by segment for the periods presented:
Year Ended December 31, 2012
Year Ended December 31, 2011
The following table sets forth revenues and assets by geographical locations for the periods reported:
5. OIL AND GAS PROPERTIES
Oil and gas properties consisted of the following as of December 31, 2012 and 2011:
Depreciation and depletion expense for oil and gas properties totaled $836,290 and $396,934 in 2012 and 2011, respectively.
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 40,000 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 plus recovery of all historical costs to develop and operate the Guaduas field, and their partnership interest may increase thereafter to 70% based on oil production results. We believe Ecopetrol could become a 50% partner the future which would reduce our field 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 present 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 in Oklahoma since the 1940s. Beginning in 2007, the application of horizontal drilling and multi-stage hydraulic fracturing treatments have demonstrated the potential for extracting significant additional quantities of oil and natural gas from the formation.
On April 21, 2011, we entered into a participation agreement (the “Participation Agreement”) with Slawson Exploration Company (“Slawson”) and 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, Oklahoma for $4,875,000. In addition, Slawson and USE carried 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 provided up to 17.5% of the total well costs. After the first three wells, the Company is responsible for up to 25% of the total well costs. Revenue from wells drilled pursuant to the Participation Agreement 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. The Participation Agreement states that Osage will deliver acreage in the Nemaha Ridge Prospect to the parties at a net Revenue Interest (“NRI”) of 78% unless Osage acquires the acreage at an NRI lower than 78%, in which case, the acreage is delivered at the NRI acquired by Osage. Where Osage acquires leases with an NRI in excess of 78%, it retains an overriding royalty interest (“ORRI”) equal to the difference between the NRI and 78%. At December 31, 2012, the Company had 7,797 net acres (47,627 gross) leased in Logan County. In December 2011, the Company participated in drilling its first well in Logan County and at December 31, 2012 the Company had participated in drilling eight wells, five of which achieved production and revenues of $2,217,279 in 2012. Also as of December 31, 2012, the Company had completed four salt water disposal wells.
In 2011, the Company began to acquire leases in Pawnee County, Oklahoma, targeting the Mississippian formation. In July 2011, we purchased from B&W Exploration, Inc. (“B&W”) the Pawnee County prospect targeting the Mississippian, for $8,500. In addition, B&W is also entitled to an overriding royalty interest on the leases acquired and a 12.5% carry on the first $200,000 of lease bonus paid in the form of an assignment of 12.5% of the leases acquired. As of December 31, 2012, the Company had 3,446 net acres (4,925 gross) leased in Pawnee County. As of December 31, 2012, none of these leases have been assigned to B&W.
In 2011, we also began to acquire leases in Coal County, Oklahoma, targeting the oily Woodford Shale formation. The oily Woodford Shale formation is located mainly in southeastern Oklahoma in the Arkoma Basin. The oily Woodford shale lies directly under the Mississippian and started as a vertical play, but horizontal drilling techniques and multi-stage fracturing technology have been used in the Woodford in recent years with much success. At December 31, 2012, we had 4,253 net (9,509 gross) acres leased in Coal County.
At December 31, 2012, we have leased 62,061 gross (15,496 net) acres across three counties in Oklahoma as follows:
6. DEBT
Activity
Apollo - Note Purchase Agreement
On April 27, 2012, we entered into a $10,000,000 senior secured note purchase agreement (“Note Purchase Agreement” or “Notes”) with Apollo Investment Corporation (“Apollo”). The Notes, which mature on April 27, 2015, are secured by substantially all of the assets of the Company, including a mortgage on all our Oklahoma leases. The Notes bear interest of Libor plus 15.0% with a Libor floor of 2.0%, with interest payable monthly. In addition, Apollo received a warrant to purchase 1,496,843 shares of common stock, exercisable at $0.01 per share, with a Black-Scholes value of $2,483,952 and an expiration date of April 27, 2017. The minimum draw amount on the Note Purchase Agreement is $1,000,000. At closing, we did not draw down any funds. At December 31, 2012, the amount outstanding under the Note Purchase Agreement was $3,000,000.
At closing of the Note Purchase Agreement, we paid $100,000 of a minimum placement fee to CC Natural Resource Partners, LLC (“CCNRP”), accrued an additional $100,000 in placement fees, and issued a warrant to purchase 250,000 shares of common stock, exercisable at $0.01 per share, with a Black-Scholes value of $413,690 and an expiration date of April 27, 2014. In addition, we paid $170,692 in legal fees, of which $100,000 were paid to Apollo. In December 2012, we paid an additional $380,000 in placement fees, $100,000 of which had been accrued. We also issued a warrant to purchase 100,000 shares of common stock, exercisable at $0.01 per share, with a Black-Scholes value of $89,952 and a term of 5 years, to the placement agent for the Note Purchase Agreement and amended the term of the warrant granted on April 27, 2012 from two to five years, with a Black-Scholes value of $1,161.
The Company recorded deferred financing costs in the aggregate amount of $3,659,448 in connection with the Note Purchase Agreement, which represented the fair value of warrants issued to Apollo and CCNRP, placement fees and legal fees, which are amortized on a straight-line basis over the term of the Notes as the Company did not draw funds at issuance.
On each anniversary of the closing date, the Company pays an administrative fee of $50,000. The Company is obligated to pay a quarterly standby fee, which accrues at a rate of 3.0%, on the amount of undrawn funds equal to the difference between $5,000,000 and the aggregate principal amount of notes issued on or after the closing date. The Company is subject to certain precedents in connection with each draw, an upfront fee equal to 2.0% of the principal amount of each draw, and is required to maintain a deposit account equal to 3 months of interest payments.
The Company is subject to various affirmative, negative and financial covenants under the Note Purchase Agreement along with other restrictions and requirements, all as defined in the Note Purchase Agreement. Affirmative covenants include by October 31st of each year beginning in 2012, a reserve report prepared as of the immediately preceding September 30, concerning the Company’s domestic oil and gas properties prepared by approved petroleum engineers, and thereafter as of September 30th of each year. Financial covenants include a $75,000 limitation per quarter on general and administrative costs in excess of the revenues generated by Cimarrona, LLC and the following:
Use of proceeds is limited to those purposes specified in the Note Purchase Agreement. As of December 31, 2012, the Company had not met the minimum production covenant, due to a revised drilling schedule and Apollo provided a waiver of the minimum production covenant. The Company did not meet the production covenant as of March 31, 2013 and has, accordingly, classified these Notes and the related Deferred Financing Costs as short-term. The Notes are subject to mandatory prepayment in the event of certain asset sales, insurance or condemnation proceeds, issuance of indebtedness, extraordinary receipts and tax refunds. All terms are as defined in the Note Purchase Agreement.
Boothbay - Secured Promissory Note
On April 17, 2012, we issued a secured promissory note (“Secured Promissory Note”) to Boothbay Royalty Co., (“Boothbay”) for gross proceeds of $2,500,000. The Secured Promissory Note matures April 17, 2014 and bears interest of 18%, payable monthly. In addition, Boothbay received 400,000 shares for which the relative fair value of $386,656 was recorded as debt discount, a 1.5% overriding royalty on our leases in section 29, township 17 North, range 3 and a 1.7143% overriding royalty on our leases in section 36, township 19 North, range 4 West in Logan County, Oklahoma. The closing price of the Company’s common stock on April 17, 2012 was $1.14. The Secured Promissory Note is secured by a first mortgage (with power of sale), security agreement and financing statement covering a 5% overriding royalty interest, proportionately reduced, in all of the Company’s leases in Logan County, Oklahoma.
In connection with the Note Purchase Agreement and the Secured Promissory Note, the Company recognized $1,288,841 of interest expense, of which $538,889 was cash interest expense, for the year ended December 31, 2012. Non-cash interest expense related to the Note Purchase Agreement and the Secured Promissory Note represented $734,976 and $114,596 for the year ended December 31, 2012.
Activity
Hoffman Note
On April 5, 2011, we issued a secured promissory note (“Hoffman Note”) to Peter Hoffman, an individual investor for $200,000. The Hoffman Note matured August 5, 2011, had a loan fee and prepaid interest of 250,000 shares of common stock, valued at $35,000, and was secured by an assignment of the Company’s future oil and gas leases in Logan County, Oklahoma. The Company repaid the Hoffman Note in full on May 24, 2011. At the time of issuance of the Hoffman Note, Mr. Hoffman owned approximately 13.2% of the Company. The Hoffman Note was agreed upon through arms-length negotiations.
Blackrock Note
On January 24, 2011, we issued a $500,000 secured promissory note to an institutional investor (the “Blackrock Note”). The Blackrock Note matured May 24, 2011, had a loan fee of $100,000, payable at the time of repayment, and was secured by an assignment of all of our current and future leases in Logan County, Oklahoma and our ownership in Cimarrona LLC. The Company repaid the Blackrock Note and the loan fee on May 24, 2011.
7. COMMITMENTS AND CONTINGENCIES
ENVIRONMENT
Osage, as owner and operator of oil and gas properties, is subject to various federal, state, and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the owner of real property and the lessee under oil and gas leases for the cost of pollution clean-up resulting from operations, subject the owner/lessee to liability for pollution damages and impose restrictions on the injection of liquids into subsurface strata.
Although Company environmental policies and practices are designed to ensure compliance with these laws and regulations, future developments and increasing stringent regulations could require the Company to make additional unforeseen environmental expenditures
The Company maintains insurance coverage that it believes is customary in the industry, although it is not fully insured against all environmental risks.
The Company is not aware of any environmental claims existing as of December 31, 2012, that would have a material impact on its consolidated financial position or results of operations. There can be no assurance, however, that current regulatory requirements will not change, or past non-compliance with environmental laws will not be discovered on the Company’s property.
LAND RENTALS AND OPERATING LEASES
In February 2011, the Company entered into a 36 month lease for its corporate offices in San Diego. The lease, including parking, was initially for $3,488 per month for the first year, increasing to $3,599 and $3,715 in the second and third years, respectively. In addition, the Company is responsible for all operating expenses and utilities. The lease required the Company to increase its security deposit from $3,381 to $10,000, with $3,299 and $3,415 of the security deposit to be applied to months 13 and 25, respectively, of the lease. In February 2012, the Company entered into a 24 month lease for a vehicle to be utilized by its operations in Oklahoma. Lease payments are $680 per month. Outside of the San Diego office and Oklahoma vehicle lease, the Company’s Oklahoma office and all leased equipment are under month-to-month operating leases.
Rental expense totaled $57,344 and $53,626 in 2012 and 2011, respectively.
Future minimum commitments under operating leases are as follows as of December 31, 2012:
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.
In 2010, the Company was notified by DIAN that it owed $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 had 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 indicated we owed for the 2003 tax year. In January 2013 we successfully concluded negotiations with DIAN with respect to the ultimate liability for the 2003 tax year. DIAN waived certain penalties and interest in the amount of $548,092. We paid the agreed final liability to DIAN in January 2013, and financed the payment with an unsecured Colombian facility. We will recognize the benefit of the amnesty upon final acceptance and receipt of official confirmation that the liability is fully settled.
The Company recorded equity taxes as follows, for the years ended December 31, 2012 and 2011:
8. INCOME TAXES
The total provision for income taxes consists of the following in 2012 and 2011:
Following is a reconciliation of the Federal statutory rate to the effective income tax rate for 2012 and 2011:
At December 31, 2012, the Company had federal and state net operating loss carry forwards of approximately $7.2 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, 2012 and December 31, 2011 (in thousands):
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 2012 and 2011, five and four customers, respectively, accounted for all of the Company’s sales:
10. LIABILITY FOR ASSET RETIREMENT OBLIGATIONS
The Company recognizes a liability at discounted fair value for the future retirement of tangible long-lived assets and associated assets retirement cost associated with the petroleum and natural gas properties. The fair value of the liability is capitalized as part of the cost of the related asset and amortized to expense over its useful life. The liability accretes until the date of expected settlement of the retirement obligations. The related accretion expense is recognized in the statement of operations. The provision will be revised for the effect of any changes to timing related to cash flow or undiscounted abandonment costs. Actual expenditures incurred for the purpose of site reclamation are charged to the asset retirement obligations 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, 2012 and 2011, because the Company records a valuation allowance on deductible temporary differences due to the uncertainty of its realization. A reconciliation of the Company’s asset retirement obligations from the periods presented is as follows:
11. SUBSEQUENT EVENTS
Subsequent to December 31, 2012, the Company has issued 400,000 shares of common stock to employees and consultants. The Company has also drawn down an additional $4,000,000 on the Apollo facility and is negotiating a larger facility with Apollo. The Company did not meet the production covenant set forth in the Apollo facility as of March 31, 2013.
12. SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
Petrotech Engineering, Ltd, and Pinnacle Energy Services, LLC prepared reserve estimates for the year-end reports for 2012 for the Cimarrona property and Logan County 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.
FASB ASC Topic 932, “Financial Accounting and Reporting by Oil and Gas Producing Companies”, 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, 2012 and 2011 are as follows:
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:
The foregoing estimates have been prepared by Petrotech Engineering, Ltd, and Pinnacle Energy Services, LLC for the Cimarrona property and Logan 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, 2012 or 2011.
The present value of estimated future net revenues of proved developed reserves, discounted at 10%, were as follows:
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.
The following table represents a reconciliation of our PV-10 to Standard Measure of discounted future net cash flows.
Depletion, depreciation and accretion per equivalent unit of production was $8.05 and $1.22 for 2012 and 2011 in the United States, respectively. In Colombia, the depletion, depreciation and accretion per equivalent unit was $9.03 and $2.68 in 2012 and 2011, respectively.
FASB ASC Topic 932, “Disclosures About Oil and Gas Producing Activities”, 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, 2012 and 2011 are as follows:
The results of operations for oil and gas producing activities for 2012 and 2011 were as follows:
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 2012 and 2011:
The principal changes in the standardized measure of discounted future net cash flows during and 2011 were as follows: