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 state of Oklahoma. We are headquartered in San Diego, California with operations offices in Oklahoma City, Oklahoma.
Mississippian
In 2010, we began to acquire oil and gas leases in Logan County, Oklahoma targeting the Mississippian formation. The Mississippian formation is located on the Anadarko Shelf in northern Oklahoma and south-central Kansas. The top of this expansive carbonate hydrocarbon system is encountered between 4,000 and 6,000 feet and lies stratigraphically between the Pennsylvanian-aged Morrow Sand and the Devonian-aged “oily” Woodford Shale formations. The Mississippian formation may reach 600 feet in gross thickness and the targeted porosity zone is between 50 and 300 feet in thickness. The formation’s geology is well understood as a result of the thousands of vertical wells drilled and produced there since the 1940s. Beginning in 2007, the application of horizontal cased-hole drilling and multi-stage hydraulic fracturing treatments have demonstrated the potential for extracting significant additional quantities of oil and natural gas from the formation.
Woodford Shale
The Woodford Shale is a major energy resource with the potential for significant unconventional oil and gas production. The Woodford is a Devonian aged, highly carboniferous black shale that has sourced the vast majority of migratable hydrocarbons in Oklahoma and Kansas. The known inefficacies of hydrocarbon expulsion is the primary reason why source rocks like the Woodford retain large volumes of oil and gas. Currently, there are more than 1,500 producing horizontal Woodford wells in Oklahoma. This world class source rock underlies all of our Mississippian acreage.
On April 21, 2011, the Company entered into a participation agreement (“Participation Agreement”) with Slawson Exploration Company (“Slawson”) and U.S. Energy Development Corporation (“USE,” Slawson and USE, together, the “Parties”). Pursuant to the terms of the Participation Agreement, Slawson and USE acquired 45% and 30% respectively, of our 10,000 acre Nemaha Ridge prospect in Logan County, Oklahoma. Slawson was the operator of all wells in the Nemaha Ridge prospect in sections where the Parties’ acreage controlled the section. In sections where the Parties’ acreage did not control the section, we may elect to participate in wells operated by others.
On December 12, 2013, Osage and Slawson entered into an agreement (the “Partition Agreement”) related to certain lands located within the Nemaha Ridge in Logan County, Oklahoma, and for the exploration and development of those leases by the Parties. Under the Partition Agreement and effective as of September 1, 2013, the Slawson Exploration Group agreed to assign all of its rights, title and interest in and to the oil and gas leases and force-pooled acreage which are part of the Nemaha Ridge Project within certain sections to Osage and Osage agreed to assign all of its rights, title and interest in and to the oil and gas leases and force-pooled acreage which are part of the Nemaha Ridge Project within certain sections to the Slawson Exploration Group, such that the net acreage controlled by the parties would remain substantially unchanged, but that the acreage controlled by each of the parties in undeveloped sections would be located in sections where the other party did not control acreage. The parties also agreed that the Participation Agreement would terminate as to all lands within the Nemaha Ridge Project except for lands within sections already developed by the parties which shall continue to be controlled by the Participation Agreement.
In September 2014, Slawson sold its interests in its oil and gas properties in Logan County, Oklahoma to Stephens Energy Group, LLC and Stephens Production Company (collectively “Stephens”).
As a result of the Partition Agreement, Osage has become the project operator on much of its acreage in the Nemaha Ridge Project. As of December 31, 2014, Osage operated or has the right to operate approximately 4,675 net acres (6,967 gross), and remains joint-venture or potential joint-venture partners with others in approximately 5,032 net acres (31,772 gross).
In 2011, we also began to acquire leases in Coal County, Oklahoma, targeting the Woodford Shale formation. The Woodford Shale formation is located mainly in southeastern Oklahoma in the Arkoma Basin. The Woodford shale lies directly under the Mississippian and started as a vertical play, but horizontal drilling techniques and multi-stage fracturing technology have been used in the Woodford in recent years with much success. At December 31, 2014, we had 4,367 net (10,106 gross) acres leased in Coal County.
In 2011, the Company began to acquire leases in Pawnee County, Oklahoma, targeting the Mississippian formation. As of December 31, 2014, the Company had 3,934 net acres (5,085 gross) leased in Pawnee County.
Cimarrona
On April 8, 2008, we entered into a Membership Interest Purchase Agreement (the “Purchase Agreement”) with Sunstone Corporation pursuant to which we acquired from them 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.
On October 7, 2013, the Company completed the sale of 100% of the membership interests in Cimarrona LLC to Raven Pipeline Company, LLC (“Raven”), pursuant to a Membership Interest Purchase Agreement dated September 30, 2013 (the “Agreement”) by and between the Company and Raven. We had classified Cimarrona as discontinued operations from August 1, 2013, as it had received an expression of interest and had concluded that a sale of its membership interests was in the best interest of stockholders.
The sales price consisted of cash of $6,550,000 exclusive of escrow, less settlement of debt of Cimarrona LLC of approximately $250,000. $250,000 was to be held in escrow for 12 months to secure any post-Closing purchase price adjustments and any indemnity obligations of the Company pursuant to the Agreement. In addition, so long as the per barrel transportation rate charged with respect to the pipeline was not adjusted prior to March 31, 2014, then Raven was obligated to pay the Company an additional $1,000,000 in cash. Pursuant to the Agreement, the Company also recognized a receivable for a working capital adjustment of $422,955 in other current assets as of December 31, 2013 and recognized a gain on disposal of discontinued operations of $4,873,660 in the year ended December 31, 2013. Raven has reimbursed the Company for the working capital adjustment. On August 31, 2014 the Company and Raven entered into a settlement agreement, due to numerous uncertainties, whereby the escrow was released to Raven and whereby no additional cash is payable by Raven to the Company.
The Cimarrona property is subject to an Ecopetrol Association Contract (the “Association Contract”) whereby Ecopetrol S.A. (“Ecopetrol”) receives royalties of 20% of the oil produced. The pipeline is not subject to the Association Contract. In addition to the royalty, according to the Association Contract, Ecopetrol may, for no consideration, become a 50% partner, once an audit of revenues and expenses indicate that the partners in the Association Contract have received a 200% reimbursement of all historical costs to develop and operate the Guaduas field. If such an audit determines that the specified reimbursement of historical costs occurred prior to September 30, 2013, the Company is required to reimburse Raven for any amounts due to Ecopetrol from Cimarrona LLC which relate to the period prior to that date. The Company believes its maximum exposure is 50% of Cimarrona LLC’s oil revenues for the nine months ended September 30, 2013, or $729,308. The Company has not recorded any provision for this matter, as it is not possible to estimate the potential liability, if any.
Background
We were organized September 9, 2004 as Osage Energy Company, LLC, an Oklahoma limited liability company. On April 24, 2006, we merged with a non-reporting Nevada corporation trading on the Pink Sheets, Kachina Gold Corporation, which was the entity that survived the merger. The merger was consummated through the issuance of 10,000,000 shares of our common stock. The financial records of the Company prior to merger are those of Osage Energy Company, LLC.
The Nevada corporation was incorporated under the laws of Canada, on February 24, 2003, as First Mediterranean Gold Resources, Inc. The domicile of the Company was changed to the State of Nevada, on May 11, 2004. On May 24, 2004, the name of the Company was changed to Advantage Opportunity Corp.
On March 4, 2005, the Company changed its name to Kachina Gold Corporation. On April 24, 2006, Kachina Gold Corporation merged with Osage Energy Company, LLC. and on May 15, 2006 changed its name to Osage Energy Corporation. On July 2, 2007, the domicile of the Company was changed to Delaware and in connection therewith, the name of the Company was changed to Osage Exploration and Development, Inc. On February 27, 2008, our stock began trading on the NASDAQ OTC Bulletin Board market under the ticker “OEDV”. Our stock currently trades on the OTCQB Marketplace.
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, natural gas and natural gas liquid sales from our production operations in Logan County in the state of Oklahoma. In 2014, we commenced our own drilling operations and became the operator of nine wells, seven of which were generating revenues at December 31, 2014. We also have a working interest in 47 other wells operated by Stephens Production Company and Stephens Energy Corp. (collectively “Stephens”), Devon Energy Production Co. LLC (“Devon”) and certain other operators and also earn an over-riding royalty interest from an additional 17 wells. 22 of the 28 wells currently operated by Stephens were previously operated by Slawson Exploration Company (“Slawson”). In August 2014, Slawson sold its interests in its oil and gas properties in Logan County, Oklahoma to Stephens. We are currently in litigation with Stephen’s, contending that we should be the operator of these wells. All of the oil produced at our operated wells is sold to Phillips 66 and all of the gas and natural gas liquids produced is sold on our behalf by Energy Financial, LLC, in both cases at market prices at the time of sale. All of the oil, natural gas and natural gas liquids produced at our non-operated properties is sold by the operators on our behalf at market prices at the time of sale. At our operated wells, we are responsible for remitting to working interest and royalty interest owners their share of oil, gas and natural gas liquid revenues. At our non-operated wells, each operator is responsible for remitting our share of the oil, gas and natural gas liquid 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 2014, Slawson, Phillips 66, Stephens and Devon accounted for 32.5%, 31.2%, 17.3% and 13.7% of our revenues from continuing operations, respectively. In 2013, Slawson, Stephens and Devon accounted for 80.0%, 10.6% and 9.2% of revenues from continuing operations, respectively.
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.
Government Approvals
We are required to get approval from the Oklahoma Corporation Commission before any work can begin on any well in Oklahoma 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 state of Oklahoma. The development and operation of oil and gas properties is highly regulated by states and/or foreign governments. In some areas of exploration and production, the United States government or a foreign governmental agency regulates the industry.
Regulations, whether state or federal or international, control numerous aspects of drilling and operating oil and gas wells, including the care of the environment, the safety of the workers and the public, and the relations with the owners and occupiers of the surface lands within or near the leasehold acreage. The effect of these regulations, whether state or federal or international, is invariably to increase the cost of operations.
The costs of complying with state regulations include a permit for drilling a well before beginning a project. Other compliance matters have to do with keeping the property free of oil spills and the plugging of wells when they no longer produce. If oil spills are not cleaned up on a timely basis fines can be significant. 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, 2014 we have incurred dismantlement and abandonment costs with respect to two wells.
Employees
We currently have nine 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, which was renewed for an additional 36 month period through February 2017. Monthly rent is $2,980, $3,084 and $3,192 for the first, second and third years, respectively, of the renewal period.
In December 2013, we entered into a 36 month lease commencing in March 2014 for 6,368 feet of executive office space for our production offices in Oklahoma City, Oklahoma. Monthly rent for this space is $11,144 for the entire duration of the lease.
In the case of both of these leases we are also responsible for our proportionate share of parking and common area expenses.
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 and at December 31, 2014 had an accumulated deficit of $38,729,362. In 2014, we recognized a non-cash provision for impairment of $29,858,178. In 2013, we recognized a one-time gain of $4,873,660 on the sale of 100% of our membership interests in Cimarrona, LLC. 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. In addition, negative trends in oil prices since the third quarter of 2014 have impacted our operating margins significantly and led to an impairment of our oil & gas properties as of December 31, 2014.
A substantial or extended decline in oil and/or gas prices could have a material and adverse effect on us.
Prices for oil and gas (including prices for natural gas liquids) fluctuate widely. At our Oklahoma properties, we sold oil at $57.87 to $105.03 per barrel in 2014 compared to $88.90 to $106.32 per barrel in 2013. Similarly, during 2014, daily settlement prices for New York Mercantile Exchange (NYMEX) for West Texas Intermediate prices ranged from a high of $107.26 per BBL to a low of $53.27 per BBL and NYMEX Henry Hub gas ranged from a high of $6.15 per million of British Thermal Units (“MMBtu”) to a low of $2.89 per MMBtu. Among the factors that can or could cause these price fluctuations are:
●the level of demand;
●domestic and global supplies of oil, natural gas liquids and gas;
●the price and quantity of imported and exported oil, natural gas liquids and gas;
●the actions of other oil exporting nations;
●weather conditions and changes in weather patterns;
●the availability, proximity and capacity of appropriate transportation facilities, gathering, processing and compression facilities and refining facilities;
●worldwide economic and political conditions, including political instability or armed conflict in oil and gas producing regions;
●the price and availability of, and demand for, competing energy sources, including alternative energy sources; and
●the nature and extent of governmental regulation, including environmental regulation, regulation of derivatives transactions and hedging activities, tax laws and regulations and laws and regulations with respect to the import and export of oil, gas and related commodities.
Our cash flows and results of operations depend to a great extent on the prevailing prices for oil and gas. Prolonged or substantial declines in oil and/or gas prices may materially and adversely affect our liquidity, the amount of cash flows we have available for our capital expenditures and other operating expenses, our ability to access the credit and capital markets and our results of operations.
Lower oil and/or gas prices may also reduce the amount of oil and/or gas that we can produce economically.
Sustained substantial declines in oil and/or gas prices may render uneconomic a significant portion of our exploration, development and exploitation projects, which may result in our having to make significant downward adjustments to our estimated proved reserves. As a result, a prolonged or substantial decline in oil and/or gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity and ability to finance capital expenditures. Additionally, if we expect or experience significant sustained decreases in oil and gas prices such that the expected future cash flows from our oil and gas properties falls below the net book value of our properties, we may be required to write down the value of our oil and gas properties. Any such asset impairments could materially and adversely affect our results of operations and, in turn, the trading price of our common stock.
We may not be able to fund the capital expenditures that will be required for us to increase reserves and production.
We must make capital expenditures to develop our existing reserves and to discover new reserves. Historically, we have financed our capital expenditures primarily with cash flow from operations, borrowings under credit facilities and sales of debt and equity securities and we expect to continue to do so in the future. There is no assurance that we will have sufficient capital resources in the future to finance all of our planned capital expenditures.
Volatility in oil and gas prices, the timing of our drilling programs and drilling results will affect our cash flow from operations. Lower prices and/or lower production could also decrease revenues and cash flow, thus reducing the amount of financial resources available to meet our capital requirements, including reducing the amount available to pursue our drilling opportunities. If our cash flow from operations does not increase as a result of planned capital expenditures, a greater percentage of our cash flow from operations will be required for debt service and operating expenses and our planned capital expenditures would, by necessity, be decreased.
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 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 federal, state and local laws and regulations primarily relating to protection of human health and the environment applicable to the development, production, handling, storage, transportation and disposal of crude oil and natural gas, byproducts thereof and other substances and materials produced or used in connection with crude oil and natural gas operations. In addition, we may inherit liability for environmental damages caused by previous owners of property we purchase or lease. As a result, we may incur substantial liabilities to third parties or governmental entities. We are also subject to changing and extensive tax laws, the effects of which cannot be predicted. The implementation of new, or the modification of existing, laws or regulations could have a material adverse effect on us.
The reserves we report in our SEC filings are estimates and may prove to be inaccurate.
There are numerous uncertainties inherent in estimating crude oil and natural gas reserves and their estimated values. The reserves we report in our filings with the SEC are only estimates and may prove to be inaccurate because of these uncertainties. Reservoir engineering is a subjective and inexact process of estimating underground accumulations of crude oil, natural gas and natural gas liquids 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.
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 and oil and gas production related equipment. Our oil and gas properties are located in the state of Oklahoma.
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 independently 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. The technical person primarily responsible for audit of our reserve estimates at Pinnacle 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. Pinnacle is an independent firm of petroleum engineers, geologists, geophysicists, and petro physicists; they do not own an interest in our properties and are not employed on a contingent fee basis. Reserve estimates are imprecise and subjective and may change at any time as additional information becomes available. Furthermore, estimates of oil and gas reserves are projections based on engineering data. There are uncertainties inherent in the interpretation of this data as well as the projection of future rates of production. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.
Pinnacle prepared reserve estimates for the year end reports for 2014 and 2013 for our continuing operations in Logan County, Oklahoma. For wells on production with sufficient historical data, remaining reserves were determined by decline curve analysis. For wells with limited production or pressure data history and those with definable reserves using offset well and reservoir parameters, remaining reserves were estimated based on analogy well and test data and other available geological and engineering information.
The Company’s estimated future net recoverable oil and gas reserves from proved reserves, both developed and undeveloped, for the properties in Logan County, Oklahoma as of December 31, 2014, 2013 and 2012 are as follows:
Using oil, gas and natural gas liquid prices and lease operating expenses in accordance with SEC guidelines, 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 $82.6 million, $40.9 million and $14.8 million at December 31, 2014, 2013 and 2012, respectively, for the Properties in Logan County, Oklahoma. Due to the sharp decline in oil prices since the third quarter of 2014, the Company does not believe that the December 31, 2014 present value calculated under SEC pricing guidelines reflects the fair value of its reserves at that date.
As of December 31, 2014, the Company had estimated proved developed and proved undeveloped reserves of crude oil of 678,000 BBLs and 2,248,000 BBLS, respectively, estimated proved developed and proved undeveloped reserves of natural gas of 2,485,000 Mcf and 6,541,000 Mcf, respectively, and estimated proved developed and proved undeveloped reserves of natural gas liquids of 414,000 BBLs and 1,090,000 BBLs, respectively. All changes in estimated proved developed and proved undeveloped reserves during 2014 were as a result of extensions and discoveries. We incurred $37,205,069 during 2014 in capital expenditures for oil and gas related properties (including $23,694,310 in converting proved undeveloped reserves to proved developed reserves). We participated in the drilling and completion of 15 productive development wells and two dry development wells during 2014 and had participated in the drilling and completion of 55 gross productive development wells as of December 31, 2014.
During 2014 we converted 235,145 BBLs of crude oil, 535,000 Mcf of natural gas and 388,104 BBLs of natural gas liquids from proved undeveloped reserves to proved developed reserves as a result of capital expenditures of $23,694,310 and added 1,344,133 BBLs of crude oil, 2,493,000 Mcf of natural gas and 1,100,652 BBLs of natural gas liquids to proved undeveloped reserves through extension and discovery.
As of December 31, 2013, the Company had estimated proved developed and proved undeveloped reserves of crude oil of 460,000 BBLs and 1,048,000 BBLS, respectively, estimated proved developed and proved undeveloped reserves of natural gas of 2,005,000 Mcf and 4,360,000 Mcf, respectively, and estimated proved developed and proved undeveloped reserves of natural gas liquids of 33,000 BBLs and 10,000 BBLs, respectively. All changes in estimated proved developed and proved undeveloped reserves during 2013 were as a result of extensions and discoveries. In December 2011, the Company commenced drilling its first development well in Logan County and incurred $17,891,932 during 2013 in capital expenditures for oil and gas related properties (including $3,261,096 in converting proved undeveloped reserves to proved developed reserves). We participated in the drilling and completion of 35 gross productive development wells during 2013 and had participated in the drilling and completion of 40 gross productive development wells as of December 31, 2013.
During 2013 we converted 127,621 BBLs of crude oil and 491,556 Mcf of natural gas from proved undeveloped reserves to proved developed reserves as a result of capital expenditures of $3,261,096 and added 1,006,621 BBLs of crude oil, 4,155,556 Mcf of natural gas and 10,000 BBLs of natural gas liquids to proved undeveloped reserves through extension and discovery.
As of December 31, 2014, the Company had no estimated proved undeveloped reserves that had remained undeveloped for more than five years, and we expect, subject to available financing, to develop all estimated proved undeveloped reserves within five years of the date of original booking.
The Company’s net oil production after other working interests and average cost per barrel for 2014 and 2013 were as follows:
The Company’s average production cost per barrel of oil equivalent is as follows:
The following summarizes the developed leasehold acreage held by the Company as of December 31, 2014 and 2013. 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, 2014 and 2013. 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.
All of the Company’s wells are development wells and, as of December 31, 2014, 2013 and 2012, the Company had no productive nor dry exploratory wells.
Drilling Activity
In December 2011, the Company commenced drilling its first well in Logan County and at December 31, 2014 the Company had commenced drilling 58 gross development wells, 54 of which achieved production and revenues as of December 31, 2014 and two of which were gross dry development wells. During 2014, we participated in drilling 14 gross productive development wells (2.7 net wells), two gross dry development wells (1.8 net wells) and two gross development wells (0.4 net wells) which had not yet achieved production and revenues as of December 31, 2014. During 2013, we participated in the drilling of 35 gross productive wells (6.1 net wells) and 2 gross wells (0.3 net wells) which had not yet achieved production and revenues as of December 31, 2013. During 2012, we participated in the drilling of 5 gross productive wells (1.1 net wells) and 3 gross wells (0.6 net wells) which had not yet achieved production as of December 31, 2012. Also as of December 31, 2014, the Company had completed six gross salt water disposal wells.
Delivery Commitments
We are obligated, under certain open oil and natural gas derivative positions to deliver monthly, through June 30, 2015, 6,000 barrels of oil and 10,000 thousand cubic foot units of natural gas.
Item 3.
Item 3. Legal Proceedings
We have initiated litigation against Stephen’s with respect to their right to operate 22 wells in which we have a working interest as we contend that we should be the operator. Neither our Company nor any of its property is a party to, or the subject of, any other 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 OTCQB Marketplace under the symbol “OEDV”. The high and low closing prices, as reported by the OTCQB Marketplace, are as follows for 2014 and 2013. 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 restrictions on our ability to distribute dividends under the terms of our Note Purchase Agreement and we are also subject to 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. In 2014, we issued 800,000 options under the Plan.
Holders
As of March 23, 2015, there were approximately 120 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 a Membership Interest Purchase Agreement (the “Purchase Agreement”) with Sunstone Corporation (“Sunstone”) pursuant to which we acquired from Sunstone 100% of the membership interests in Cimarrona Limited Liability Company, an Oklahoma limited liability company (“Cimarrona LLC”). Cimarrona LLC owns a 9.4% interest in certain oil and gas assets in the Guaduas field, located in the Dindal and Rio Seco Blocks that consist of 21 wells, of which seven are currently producing, that covers 30,665 acres in the Middle Magdalena Valley in Colombia as well as a pipeline with a current capacity of approximately 40,000 barrels of oil per day. The Purchase Agreement was effective as of April 1, 2008. The Cimarrona property is subject to an Ecopetrol Association Contract (the “Association Contract”) whereby we pay Ecopetrol S.A. (“Ecopetrol”) royalties of 20% of the oil produced. The pipeline is not subject to the Association Contract. The royalty amount for the Cimarrona property is paid in oil. The property and the pipeline are both operated by Pacific, which owns 90.6% of the Guaduas field. Pipeline revenues generated from the Cimarrona property primarily relate to transportation costs charged to third party oil producers, including Pacific.
On October 7, 2013, the Company completed the sale of 100% of the membership interests in Cimarrona LLC to Raven Pipeline Company, LLC (“Raven”), pursuant to a Membership Interest Purchase Agreement (the “Agreement”) dated September 30, 2013 by and between the Company and Raven. Accordingly, the Company will not recognize any revenues or expenses for Cimarrona LLC from October 1, 2013. The sales price consisted of cash of $6,550,000 exclusive of escrow, less settlement of debt of Cimarrona LLC of approximately $250,000. Pursuant to the Agreement, the Company also recognized a receivable for a working capital adjustment of $422,955 in other current assets as of December 31, 2013 and recognized a gain on disposal of discontinued operations of $4,873,660 in the year ended December 31, 2013.
In 2010, we began to acquire oil and gas leases in Logan County, Oklahoma targeting the Mississippian formation. The Mississippian formation is located on the Anadarko Shelf in northern Oklahoma and south-central Kansas. The top of this expansive carbonate hydrocarbon system is encountered between 4,000 and 6,000 feet and lies stratigraphically between the Pennsylvanian-aged Morrow Sand and the Devonian-aged Woodford Shale formations. The Mississippian formation may reach 600 feet in gross thickness and the targeted porosity zone is between 50 and 300 feet in thickness. The formation’s geology is well understood as a result of the thousands of vertical wells drilled and produced there since the 1940s. Beginning in 2007, the application of horizontal cased-hole drilling and multi-stage hydraulic fracturing treatments have demonstrated the potential for extracting significant additional quantities of oil and natural gas from the formation.
The Woodford Shale is a major energy resource with the potential for significant unconventional oil and gas production. The Woodford is a Devonian aged, highly carboniferous black shale that has sourced the vast majority of migratable hydrocarbons in Oklahoma and Kansas. The known inefficacies of hydrocarbon expulsion is the primary reason why source rocks like the Woodford retain large volumes of oil and gas. Currently, there are more than 1,500 producing horizontal Woodford wells in Oklahoma. This source rock underlies all of our Mississippian acreage.
On April 21, 2011, the Company entered into a participation agreement (“Participation Agreement”) with Slawson and U.S. Energy Development Corporation (“USE,” Slawson and USE, together, the “Parties”). Pursuant to the terms of the Participation Agreement, Slawson and USE acquired 45% and 30% respectively, of our 10,000 acre Nemaha Ridge prospect in Logan County, Oklahoma for $4,875,000. In addition, the Parties carried Osage for 7.5% of the cost of the first three horizontal Mississippian wells, which means that for the first three horizontal Mississippian wells, the Company provided up to 17.5% of the total well costs. After the first three wells, the Company was responsible for up to 25% of the total well costs. Revenue from wells drilled pursuant to the Participation Agreement, after royalty and third party acreage interest payments, was allocated 45% to Slawson, 30% to USE and 25% to Osage. Slawson was the operator of all wells in the Nemaha Ridge prospect in sections where the Parties’ acreage controlled the section. In sections where the Parties’ acreage did not control the section, we may elect to participate in wells operated by others.
On December 12, 2013, Osage and Slawson entered into an agreement (the “Partition Agreement”) related to certain lands located within the Nemaha Ridge in Logan County, Oklahoma, and for the exploration and development of those leases by the Parties.
Under the Partition Agreement and effective as of September 1, 2013, Slawson agreed to assign all of its rights, title and interest in and to the oil and gas leases and force-pooled acreage which are part of the Nemaha Ridge Project within certain sections to Osage and Osage agreed to assign all of its rights, title and interest in and to the oil and gas leases and force-pooled acreage which are part of the Nemaha Ridge Project within certain sections to the Slawson Exploration Group, such that the net acreage controlled by the parties would remain substantially unchanged, but that the acreage controlled by each of the parties in undeveloped sections would be located in sections where the other party did not control acreage. The parties also agreed that the Participation Agreement would terminate as to all lands within the Nemaha Ridge Project except for lands within sections already developed by the parties which shall continue to be controlled by the Participation Agreement.
In September 2014, Slawson sold its interests in its oil and gas properties in Logan County, Oklahoma to Stephens.
As a result of the Partition Agreement, Osage has become the project operator on much of its acreage in the Nemaha Ridge Project. As of December 31, 2014, Osage operated or has the right to operate approximately 4,675 net acres (6,967 gross), and remains joint-venture or potential joint-venture partners with others in approximately 5,032 net acres (31,772 gross).
In 2011, we also began to acquire leases in Coal County, Oklahoma, targeting the Woodford Shale formation. The Woodford Shale formation is located mainly in southeastern Oklahoma in the Arkoma Basin. The Woodford shale lies directly under the Mississippian and started as a vertical play, but horizontal drilling techniques and multi-stage fracturing technology have been used in the Woodford in recent years with much success. At December 31, 2014, we had 4,367 net (10,106 gross) acres leased in Coal County.
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. Subsequently, B&W shall have an option to purchase a 12.5% share of leasehold acquired on a heads-up basis. As of December 31, 2014, the Company had 3,934 net acres (5,085 gross) leased in Pawnee County.
At December 31, 2014, we have leased 18,008 net (53,930 gross) acres across three counties in Oklahoma as follows:
The Company has accumulated deficits of $38,729,362 and $4,219,480 and working capital deficits of $36,213,063 and $12,961,622 as of December 31, 2014 and 2013, respectively. Substantial portions of the losses are attributable to impairment charges, stock-based compensation, professional fees and interest expense. Negative trends in oil prices since the third quarter of 2014 have impacted our operating margins significantly and led to an impairment of our oil & gas properties as of December 31, 2014.
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) becoming an operator of our own wells, (b) participating in drilling of wells in Logan County, Oklahoma, (c) controlling overhead and expenses, (d) selling parts of our existing operations, and (e) raising additional equity and/or debt.
On April 27, 2012, we entered into a $10,000,000 senior secured note purchase agreement with Apollo Investment Corporation. On April 5, 2013 we amended this agreement, increasing the facility to $20,000,000 and on April 3, 2014 we further amended this agreement, increasing the facility to $30,000,000, extending the term of the facility by one year, reducing the interest rate from Libor plus 15% to Libor plus 11% and agreeing to modify the covenants to reflect the transition from participant to operator. On April 7, 2014, we drew down an additional $5 million, bringing total borrowings under the Note Purchase Agreement to $25 million. We are in discussions with respect to new covenants to reflect becoming an operator of our own wells and with respect to negative trends in oil prices which have diminished Apollo Investment Corporation’s security interest in our reserves. Existing covenants, some of which we are not in compliance with, remain in effect until the new covenants are agreed upon. Because we are not in compliance with certain existing covenants, we have classified the Note Purchase Agreement obligations as current in the accompanying financial statements.
In February 2014, the Company initiated a private placement, pursuant to Securities Purchase Agreements between Osage and certain purchasers, with aggregate gross proceeds of approximately $6.7 million. The purchase price of each unit, representing one share of common stock and a warrant to purchase 0.4 shares of common stock at $1.80 per share, was $0.90. The warrants have a term of five years. The placement agent received placement fees of 8%, in cash or warrants or a combination thereof at their election.
The Company’s operating plans require additional funds which may take the form of debt or equity financings. The Company’s ability to continue as a going concern is in substantial doubt and is dependent upon achieving profitable operations and obtaining additional financing. There is no assurance additional funds will be available on acceptable terms or at all. 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.
Results of Operations
Year ended December 31, 2014 compared to year ended December 31, 2013
Oil Sales
Oil sales were $10,481,767, in 2014, an increase of $3,141,824, or 42.8%, compared to $7,339,943 in 2013. The increase in oil sales is due to additional wells in production in Logan County, Oklahoma. We sold 120,264 barrels (“BBLs”) in 2014 at an average gross price of $75.46 per barrel, compared to 74,567 BBLs in 2013 at an average price of $97.31 per barrel.
Natural Gas and Natural Gas Liquids Sales
Natural gas and natural gas liquids sales were $2,196,749 for the year ended December 31, 2014 compared to $689,145 for the year ended December 31, 2013 an increase of $1,507,604 or 218.8%. 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 aa “Mcf.” and natural gas liquid production is measured in BBLs. We sold 364,726 Mcf of natural gas at an average of $4.40 per Mcf in 2014 compared to 141,506 Mcf at $3.97 per Mcf in 2013. The price achieved per BBL for 27,201 BBLs of natural gas liquids in 2014 was $28.84 compared to $28.88 for 3,306 BBLs in 2013.
Total Revenues
Total revenues were $12,678,516, an increase of $4,649,428, or 57.9% for the year ended December 31, 2014 compared to $8,029,088 for the year ended December 31, 2013. Oil sales accounted for 82.7% and 91.4% of total revenues in the 2014 and 2013 periods, respectively.
Production
Oil production, net of royalties, was 124,278 BBLs, an increase of 47,869 BBLs, or 62.6%, for the year ended December 31, 2014 compared to 76,409 BBLs for the year ended December 31, 2013, due to production increases as a result of additional wells
Natural gas production was 367,441 Mcf, an increase of 217,703 Mcf, or 145.4%, for the year ended December 31, 2014, compared to 149,738 Mcf for the year ended December 31, 2013.
Natural gas liquid production was 27,756 BBLs, an increase of 24,249 BBLs, or 691.4%, for the year ended December 31, 2014, compared to 3,507 BBLs for the year ended December 31, 2013.
Operating Costs and Expenses
Well operating expenses
Our well operating expenses in 2014 were $1,935,367, an increase of $387,418, or 25.0% compared to $1,547,949 in 2013, due primarily to an increase in the number of wells in operation in Logan County, Oklahoma. Operating expenses as a percentage of total revenues decreased to 15.3% in 2014 from 19.3% in 2013, as the percentage increase in operating expenses was less than the percentage increase in revenues as new wells came into production. Production Cost/BOE for 2014 was $9.07 compared to $14.76 for 2013.
General and administrative expenses
General and administrative expenses in 2014 were $6,164,129, an increase of $3,550,209, or 135.8%, compared to $2,613,920 in 2013. The increase is primarily due to an increase in stock based compensation of $2,723,740 to $3,252,158 in 2014, along with an increase in legal and professional fees of $390,075 to $763,277, an increase in salaries of $140,933 to $1,073,313 and an increase in write off of expired mineral leases of $279,131 to $323,848. As a percentage of revenues, general and administrative expenses increased to 48.6% in 2014 from 32.6% in 2013. Excluding stock based compensation, general and administrative expenses were $2,911,971 in 2014, or 23.0% of revenues, compared to $2,085,502 in 2013, or 26.0% of revenues.
Depreciation, depletion and accretion
Depreciation, depletion and accretion were $6,729,974 for the year ended December 31, 2014 and $2,320,441 for the year ended December 31, 2013, an increase of $4,409,533 or 190.0%, due to increased wells in production. Our depletion expense will continue to increase to the extent we are successful in our well production in Oklahoma.
Impairment of oil and gas properties
Impairment of oil and gas properties was $29,858,178 for the year ended December 31, 2014. This impairment related to proved properties in the Logan County Field, due to low commodity prices. The Company incurred no impairment charges for the year ended December 31, 2013. See Part II, Item 7A.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
We have material exposure to interest rate changes, as our $25,000,000 secured promissory note carries an interest rate of the London interbank overnight rate (“Libor”) plus 11%, with a Libor floor of 2%. We are subject to changes in the price of oil, which are out of our control. At our Oklahoma Properties, we sold oil at $57.87 to $105.03 per barrel in 2014 compared to $88.90 to $106.32 per barrel in 2013.
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 natural gas is set by market forces beyond our control as well as governmental intervention. The volatility and uncertainty in oil and natural gas prices have made it more difficult for a company like us to increase our oil and natural gas asset base and become a significant participant in the oil and gas industry. We currently sell the majority our oil and natural gas production to Slawson, Phillips 66, Stephens and Devon. However, in the event these customers discontinued oil and gas purchases, we believe we can replace them with other customers which would purchase the oil and gas at terms standard in the industry.
Critical Accounting Policies and Estimates
Management’s Discussion and Analysis of Financial Condition and Results of Operations discusses our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. On an on-going basis, management evaluates our estimates and judgments, including those related to revenue recognition, recovery of oil and gas reserves, financing operations, and contingencies and litigation.
Oil and Gas Properties
We follow the “successful efforts” method of accounting for our oil and gas exploration and development activities, as set forth in the Statement of Financial Accounting Standards (SFAS) No. 19, as codified by FASB ASC topic 932. Under this method, we initially capitalize expenditures for oil and gas property acquisitions until they are either determined to be successful (capable of commercial production) or unsuccessful. The carrying value of all undeveloped oil and gas properties is evaluated periodically and reduced if such carrying value appears to have been impaired. Leasehold costs relating to successful oil and gas properties remain capitalized while leasehold costs which have been proven unsuccessful are charged to operations in the period the leasehold costs are proven unsuccessful. Costs of carrying and retaining unproved properties are expensed as incurred.
The costs of drilling and equipping development wells are capitalized, whether the wells are successful or unsuccessful. The costs of drilling and equipping exploratory wells are capitalized until they are determined to be either successful or unsuccessful. If the wells are successful, the costs of the wells remain capitalized. If, however, the wells are unsuccessful, the capitalized costs of drilling the wells, net of any salvage value, are charged to operations in the period the wells are determined to be unsuccessful.
The provision for depreciation and depletion of oil and gas properties is computed on the unit-of-production method. Under this method, we compute the provision by multiplying the total unamortized costs of oil and gas properties including future development, site restoration, and dismantlement abandonment costs, but excluding costs of unproved properties by an overall rate determined by dividing the physical units of oil and gas produced during the period by the total estimated units of proved oil and gas reserves. This calculation is done on a field-by-field basis. As of December 31, 2014 and 2013, our oil and natural gas production continuing operations were conducted in Logan County 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 SFAS No. 143, “Accounting for Asset Retirement Obligations,” as codified by FASB ASC topic 410, we report a liability for any legal retirement obligations on our oil and gas properties. The asset retirement obligations represent the estimated present value of the amounts expected to be incurred to plug, abandon, and remediate the producing properties at the end of their productive lives, in accordance with state laws, as well as the estimated costs associated with the reclamation of the property surrounding. The Company determines the asset retirement obligations by calculating the present value of estimated cash flows related to the liability. The asset retirement obligations are recorded as a liability at the estimated present value as of the asset’s inception, with an offsetting increase to producing properties. Periodic accretion of the discount related to the estimated liability is recorded as an expense in the statement of operations.
The estimated liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells, and a risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligations. Revisions to the asset retirement obligations are recorded with an offsetting change to producing properties, resulting in prospective changes to depletion and depreciation expense and accretion of the discount. Because of the subjectivity of assumptions and the relatively long lives of most of the wells, the costs to ultimately retire the Company’s wells may vary significantly from prior estimates.
We review our proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the expected undiscounted future cash flows of our oil and natural gas properties and compare such undiscounted future cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value are subject to our judgment and expertise and include, but are not limited to, actual or proposed recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. We recorded an impairment charge of $29,858,178 in 2014. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges for proved properties will be recorded.
We assess our unproved properties periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage and record impairment expense for any decline in value.
The assessment of unproved properties to determine any possible impairment requires significant judgment. No impairment was recorded on unproved properties in 2014 or 2013.
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, except as disclosed in the consolidated financial statements, under which we have:
● an obligation under a guarantee contract,
● a retained or contingent interest in assets transferred to the unconsolidated entity or similar arrangement that serves as credit, liquidity or market risk support to such entity for such assets,
● any obligation, including a contingent obligation, under a contract that would be accounted for as a derivative instrument, or
● any obligation, including a contingent obligation, arising out of a variable interest in an unconsolidated entity that is held by us and material to us where such entity provides financing, liquidity, market risk or credit risk support to, or engages in leasing, hedging or research and development services with us.
Item 8.
Item 8. Financial Statements and Supplementary Data
Our consolidated financial statements as of December 31, 2014 and December 31, 2013 and for the fiscal years then ended were audited by Mayer Hoffman McCann P.C., 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 January 2014 we dismissed MaloneBailey, LLP and appointed Mayer Hoffman McCann P.C. as our independent registered public accounting firm. 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, 2014, 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, 2014 is not effective. Based on this assessment, management has determined that, as of December 31, 2014, there were material weaknesses in our internal control over financial reporting. The material weaknesses identified during management’s assessment was the lack of independent oversight by an audit committee of independent members of the Board of Directors. As defined by the Public Company Accounting Oversight Board Auditing Standard No. 5, a material weakness is a deficiency or a combination of deficiencies, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected. During the year ended December 31, 2014, the Company appointed one independent director and the Board performed the duties of 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 year ending December 31, 2014 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
PART III
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 of the Board
February 2007
Greg Franklin
Chief Geologist, Director
May 2005
Gregory Holcombe
Director
August 2014
Norman Dowling
Chief Financial Officer
N/A
A list of current executive officers and directors appears above. The executive officers serve at the pleasure of the Board of Directors. 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 of 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.
Gregory Holcombe: Mr. Holcombe currently serves on the Board of Directors at Hudson Valley Bank, a publicly-traded $3 billion bank located in Westchester County, New York, where he is on the Loan and Oversight Committees. Mr. Holcombe has been a member of the Board of Directors at Hudson Valley Bank since 1999. Mr. Holcombe graduated from Tulane University in 1983 with a BS in Latin American Studies and International Marketing.
Norman Dowling: Mr. Dowling has been our part time Chief Financial Officer since January 2013 and became full time in March 2014. Since 2009, Mr. Dowling has been providing senior financial consulting services to a range of entities in the retail, technology, and education sectors. Mr. Dowling has over 20 years of finance experience, including four years 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, and four years as Vice President Finance, at PETCO Animal Supplies, Inc. (“PETCO”) from 1999 through 2004, 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. and CinemaStar Luxury Theatres, Inc. 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, 2014.
Audit Committee
We do not have an Audit Committee, as our Board of Directors during 2014 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. Only one of our directors, Gregory Holcombe, is independent and 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 Board performs 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 Board of Directors. 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 named 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.
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 and in March 2014 Mr. Dowling began serving in a full-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 herein:
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 23, 2015 with respect to each beneficial owner of more than five percent of the Company’s Common stock:
The percentage ownership is based on 58,284,948 shares outstanding at March 25, 2015.
[1] Information is derived from Schedule 13D filed by Mustang Capital Venture, LLC on March 16, 2009.
The following table shows information as of March 23, 2015 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 58,284,948 shares outstanding at March 23, 2015.
There are no family relationships among the directors and executive officers.
(1) Includes 1,632,509 shares and 555,555 warrants to purchase shares. Of the 2,188,064 shares and warrants, 1,648,668 are held directly by Mr. Holcombe, 49,461 are held by he and his spouse, 44,963 are held by his spouse, 233,334 are held by Eldred Preserve LLC, 202,318 are held by Heidi Foundation and 9,320 are held by BMW Machinery.
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, 2014, there are 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 Board of Directors is made up of Kim Bradford, our President and Chief Executive Officer, Gregory Holcombe, an independent director 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 Stock Market LLC (“NASDAQ”). NASDAQ Marketplace Rule 5605(a)(2). This requires, among other things, that the Company’s board of directors make an affirmative determination that the director has no relationship which would interfere with the exercise of independent judgement in carrying out the responsibilities of a director. The Rule also requires that in making a determination of independence the board of directors must consider the source of a director’s compensation, including the receipt of compensatory fees from the Company or its subsidiaries. At this time, the Board has determined that only one of its directors is independent.
Item 14.
Item 14. Principal Accounting Fees and Services
Selection of our Independent Registered Public Accounting Firm is made by the Board of Directors. Mayer Hoffman McCann P.C. (“MHM”) has been selected as our Independent Registered Public Accounting Firm for the current fiscal year. MHM leases substantially all its personnel, who work under the control of MHM shareholders, from wholly-owned subsidiaries of CBIZ, Inc., in an alternative practice structure. All audit and non-audit services provided by MHM are pre-approved by the Board of Directors which gives due consideration to the potential impact of non-audit services on auditor independence.
In accordance with applicable requirements of the Public Company Accounting Oversight Board regarding the independent accountant’s communications with the audit committee concerning independence, we received a letter and verbal communication from MHM that it knows of no state of facts which would impair its status as our independent public accountants. There were no non-audit services provided by our Independent Registered Public Accounting Firms in 2014 or 2013.
AUDIT FEES
For 2014, we were or will be billed $168,000 by MHM and for 2013, we were billed $105,000 by MHM and $32,500 by MaloneBailey, LLP, for audit services.
TAX FEES
Our auditors did not bill us for any tax services during 2014 and 2013.
ALL OTHER FEES
Our auditors did not bill us for any other services during 2014 and 2013 other than $8,500 by MaloneBailey, LLP for certain consents in 2014.
PART IV
Item 15.
Item 15. Exhibit, Financial Statements Schedules
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)
10.11
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)
10.17
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)
10.19
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
$10 million Note Purchase Agreement with Apollo Investment Corp. (18)
10.24.1
First Amendment to Note Purchase Agreement (19)
10.24.2
Second Amendment to Note Purchase Agreement (20)
10.25
Membership Interest Purchase Agreement (21)
10.26
Intercreditor Agreement with BP Energy (21)
10.27
Partition Agreement with Slawson Exploration Company, Inc. (22)
10.28
Form of Securities Purchase Agreement (23)
10.29
Form of Common Stock Purchase Warrant (23)
10.30
Pinnacle Energy LLC reserve report for the Logan Property as of December 31, 2012 (24)
10.31
Pinnacle Energy LLC reserve report for the Logan Property as of December 31, 2014 (*)
10.31.1
Consent of Pinnacle Energy LLC (*)
10.32
Participation Agreement with Slawson Exploration Company and US Energy Development Corporation (25)
10.33
Third Amendment to Note Purchase Agreement (26)
10.34
Settlement Agreement with Raven Pipeline Co LLC (27)
21.1
List of Subsidiaries (*)
31.1
Certification of Chief Executive pursuant to Rule 13a-14 and Rule 15d-14(a), promulgated under the Securities and Exchange Act of 1934, as amended. (*)
31.2
Certification of Chief Financial pursuant to Rule 13a-14 and Rule 15d-14(a), promulgated under the Securities and Exchange Act of 1934, as amended. (*)
32.1
Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Chief Executive Officer) (*)
32.2
Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Chief Financial Officer) (*)
101.INS
XBRL Instance Document **
101.SCH
XBRL Taxonomy Extension Schema Document **
101.CAL
XBRL Taxonomy Extension Calculation Linkbase Document **
101.DEF
XBRL Taxonomy Extension Definition Linkbase Document **
101.LAB
XBRL Taxonomy Extension Label Linkbase Document **
101.PRE
XBRL Taxonomy Extension Presentation Linkbase Document **
(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
(17) Incorporated by reference to Osage’s Form 10-K filed April 2, 2013
(18) Incorporated by reference to Osage’s Form 8-k filed May 1,
(19) Incorporated by reference to Osage’s Form 8-k filed April 8, 2013
(20) Incorporated by reference to Osage’s Form 10-Q filed August 14, 2013
(21) Incorporated by reference to Osage’s Form 10-Q filed November 11, 2013
(22) Incorporated by reference to Osage’s Form 8-k filed December 23, 2013
(23) Incorporated by reference to Osage’s Form 8-k filed February 25, 2014
(24) Incorporated by reference to Osage’s Form 10-K filed March 31, 2014
(25) Incorporated by reference to Osage’s Form 10-K/A filed September 24, 2014
(26) Incorporated by reference to Osage’s Form 8-k filed April 4, 2014
(27) Incorporated by reference to Osage’s Form 10-Q filed November 13, 2014
** In accordance with Regulation S-T, the XBRL-formatted interactive data files that comprise Exhibit 101 in this Annual Report on Form 10-K shall be deemed “furnished” and not “filed”.
SIGNATURES
In accordance with the requirements of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
OSAGE EXPLORATION & DEVELOPMENT, INC.
BY: /s/ KIM BRADFORD
Kim Bradford
President and C.E.O.
Dated: March 31, 2015
BY: /s/ Norman Dowling
Norman Dowling
Chief Financial Officer
Dated: March 31, 2015
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
March 31, 2015
Kim Bradford
(Principal Executive Officer)
/s/ GREG FRANKLIN
Chief Geologist and Director
March 31, 2015
Greg Franklin
/s/ GREGORY HOLCOMBE
Director
March 31, 2015
Gregory Holcombe
/s/ NORMAN DOWLING
Chief Financial Officer
March 31, 2015
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, 2014 and 2013:
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Osage Exploration and Development, Inc.
We have audited the accompanying consolidated balance sheets of Osage Exploration and Development, Inc. as of December 31, 2014 and 2013, and the related consolidated statements of operations and other comprehensive income (loss), stockholders’ equity (deficit) and cash flows for the years 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 audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the 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 audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Osage Exploration and Development, Inc. as of December 31, 2014 and 2013, and the consolidated results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.
The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the financial statements, the Company has incurred recurring losses from operations and, as of December 31, 2014, has current liabilities significantly in excess of current assets. These conditions, among others as discussed in Note 2 to the financial statements, raise substantial doubt about its ability to continue as a going concern. Management’s plans regarding these matters are also described in Note 2. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.
San Diego, California
March 31,
OSAGE EXPLORATION AND DEVELOPMENT, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
As of December 31, 2014 and December 31, 2013
The accompanying notes are an integral part of these consolidated financial statements.
OSAGE EXPLORATION AND DEVELOPMENT, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND OTHER COMPREHENSIVE INCOME (LOSS)
For Years Ended December 31, 2014 and 2013
The accompanying notes are an integral part of these consolidated financial statements.
OSAGE EXPLORATION AND DEVELOPMENT, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (Deficit)
For Years Ended December 31, 2014 and December 31, 2013
The accompanying notes are an integral part of these consolidated financial statements.
OSAGE EXPLORATION AND DEVELOPMENT, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For Years Ended December 31, 2014 and 2013
The accompanying notes are an integral part of these consolidated financial statements.
OSAGE EXPLORATION AND DEVELOPMENT, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2014 and 2013
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
NATURE OF OPERATIONS
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, natural gas and natural gas liquids. The Company’s production activities are located in the State of Oklahoma. The principal executive offices of the Company are at 2445 Fifth Avenue, Suite 310, San Diego, CA 92101.
BASIS OF CONSOLIDATION
The consolidated financial statements include the accounts of Osage and its wholly owned subsidiaries, Osage Energy Company, LLC and Osage Exploration and Development Operating, 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. The results, assets and liabilities of the Company’s former wholly owned subsidiary, Cimarrona, LLC, have been presented as discontinued operations in the consolidated financial statements.
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 2014 or 2013.
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 impairment, 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 15: 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 $3,959,448 are being amortized over the term of the Note Purchase Agreement on a straight-line basis. In 2014, the term of the Note Purchase Agreement was extended by one year.
During the years ended December 31, 2014 and 2013, respectively, the Company made payments of $100,000 and $200,000 for deferred financing fees in connection with the Note Purchase Agreement.
Deferred financing costs at December 31, 2014 and 2013 were $1,009,642 and $1,829,124, respectively. Amortization of deferred financing costs was $919,482 for the year ended December 31, 2014 and $1,295,348 for the year ended December 31, 2013.
FAIR VALUE OF FINANCIAL INSTRUMENTS
As of December 31, 2014 and December 31, 2013, the fair value of cash, accounts receivable, short term debt 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 use 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, 2014 and December 31, 2013 the Company identified certain derivative financial instruments which required disclosure at fair value on the balance sheets.
The following table presents information for those assets and liabilities requiring disclosure at fair value as of December 31, 2014 and December 31, 2013:
The following methods and assumptions were used to estimate the fair values in the tables above.
Level 2 Fair Value Measurements
Commodity derivatives - The fair values of commodity derivatives are estimated using internal option pricing models based upon forward curves and data obtained from independent third parties for contracts with similar terms or data obtained from counterparties to the agreements.
Assets and Liabilities Measured on a non-recurring basis
The Company utilizes fair value on a non-recurring basis to perform impairment tests on its oil & gas properties when required. During the year ended December 31, 2014, the Company recognized impairment on proved oil & gas properties of $29,858,178. These proved oil & gas properties are located in the Logan County Field in Oklahoma and the fair value evaluation was performed on a field basis. The factors used to determine fair value are subject to our judgment and expertise and include, but are not limited to, recent actual or proposed sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected and would generally be classified within Level 3.
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 2014 and 2013. 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 five customers in 2014 and four customers in 2013. (See “Accounts Receivable and Allowance for Doubtful Accounts” below).
RESTRICTED CASH
In connection with the Apollo Note Purchase Agreement, as amended (see Note 6), the Company has classified $812,500 and $850,000, representing three months interest, as restricted cash as of December 31, 2014 and 2013, respectively. The Company has also pledged $83,867 and $58,645 for certain bonds and sureties as of December 31, 2014 and 2013, respectively. Restricted cash at December 31, 2014 was $896,367, compared to $908,645 at December 31, 2013.
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 year ended December 31, 2014, the Company sold 81.0% of its oil and gas production to three customers. 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, 2014 and 2013. 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 the state of Oklahoma.
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, 2014 and 2013, the Company’s oil production operations are conducted in the United States of America. The cost of unevaluated properties not being amortized, to the extent there is such a cost, is assessed quarterly to determine whether the value has been impaired below the capitalized cost. The 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, 2014 and 2013.
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 statements 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.
We review our proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the expected undiscounted future cash flows of our oil and natural gas properties and compare such undiscounted future cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we adjust the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value are subject to our judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. We recorded an impairment charge of $29,858,178 in 2014. During 2013, we did not record any charge for impairment. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges for proved properties will be recorded.
We assess our unproved properties periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage and record impairment expense for any decline in value.
The assessment of unproved properties to determine any possible impairment requires significant judgment. No impairment was recorded on unproved properties in 2014 or 2013.
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 has no imbalance positions at December 31, 2014 or 2013, and no receivables, payables or unearned revenue are recorded.
STOCK BASED COMPENSATION
The Company accounts for its stock-based compensation in accordance with FASC ASC topic 718. The Company recognizes in the statement of operations the grant-date fair value of stock options and other equity-based compensation issued to employees and non-employees over the requisite service period. For stock-based awards the value is based on the market value for the stock on the date of grant and if the stock has restrictions as to transferability a discount is provided for lack of tradability. Stock option awards are valued using the Black-Scholes option-pricing model. For shares issued for services or property, the value is based on the market value for the stock on the date of grant.
INCOME TAXES
The Company follows FASB ASC Topic 740 (“ASC 740”), “Accounting for Uncertainty in Income Taxes.” 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.
RISK MANAGEMENT ACTIVITIES
The Company has entered into certain derivative financial instruments to manage the inherent uncertainty of future revenues. The Company does not intend to hold or issue derivative financial instruments for speculative purposes and has elected not to designate any of its derivative instruments for hedge accounting treatment. These derivative financial instruments are marked to market at each reporting period.
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.
The following table shows the computation of basic and diluted net income (loss) per share for the years ended December 31, 2014 and 2013:
Warrants and options to purchase 7,487,559 and 1,696,843 shares of common stock at December 31, 2014 and December 31, 2013, respectively, were excluded from the computation as their effect would have been anti-dilutive.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In May 2014, the FASB issued Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers. The ASU will supersede most of the existing revenue recognition requirements in GAAP and will require entities to recognize revenue at an amount that reflects the consideration to which it expects to be entitled in exchange for transferring goods or services to a customer. The new standard also requires disclosures sufficient to enable users to understand an entity’s nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The new standard is effective for the Company on January 1, 2017. Early application is not permitted. The standard permits the use of either the retrospective or cumulative effect transition method.
In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements-Going Concern: Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern, which provides guidance on determining when and how reporting entities must disclose going-concern uncertainties in their financial statements. The new standard requires management to perform interim and annual assessments of an entity’s ability to continue as a going concern within one year of the date of issuance of the entity’s financial statements. Further, an entity must provide certain disclosures if there is substantial doubt about the entity’s ability to continue as a going concern. The ASU is effective for annual periods ending after December 15, 2016 and interim periods thereafter, and early adoption is permitted.
The Company is evaluating the impact, if any, that ASU 2014-09 and ASU 2014-15 will have on its consolidated financial statements.
2. GOING CONCERN
The Company has an accumulated deficit of $38,729,362 and a working capital deficit of $36,213,063 as of December 31, 2014. As of December 31, 2014, the Company was not in compliance with certain covenants including the minimum production covenant under the senior secured note purchase agreement. (see Note 6 - Debt). These factors raise substantial doubt about the Company’s ability to continue as a going concern.
On April 27, 2012, we entered into a $10,000,000 senior secured note purchase agreement with Apollo Investment Corporation, on April 5, 2013 we amended this agreement, increasing the facility to $20,000,000. On April 3, 2014, the Company and Apollo amended the Note Purchase Agreement, increasing the amount of the total facility to $30,000,000, extending the term by one year and reducing the interest rate from Libor plus 15% to Libor plus 11%. During the year ended December 31, 2014, we drew down $5,000,000 of additional funds and, as of December 31, 2014, the amount outstanding under the senior secured note purchase agreement was $25,000,000.
In early 2014, the Company raised approximately $6.7 million of gross proceeds in a private placement.
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) becoming operators of our own wells, (b) participating in drilling of wells in Logan County, Oklahoma within the next 12 months, (c) controlling overhead and expenses, (d) selling portions of existing operations, and (e) raising additional equity and/or debt.
The Company’s operating plans require additional funds which may take the form of debt or equity financings. The Company’s ability to continue as a going concern is dependent upon achieving profitable operations and obtaining additional financing. Our cash flows and results of operations depend to a great extent on the prevailing prices for oil and gas. Prolonged or substantial declines in oil / and/or gas prices may materially and adversely affect our liquidity, the amount of cash flows we have available for our capital expenditures and other operating expenses, our ability to access credit and capital markets and our results of operations. There is no assurance additional funds will be available on acceptable terms or at all.
These consolidated financial statements do not give effect to any adjustments which would be necessary should the Company be unable to continue as a going concern and therefore be required to realize its assets and discharge its liabilities in other than the normal course of business and at amounts different from those reflected in the accompanying consolidated financial statements.
3. EQUITY TRANSACTIONS
Common Stock and Options
In February 2014, the Company initiated a private placement, pursuant to Securities Purchase Agreements between Osage and certain purchasers, with aggregate gross proceeds of approximately $6.7 million. The purchase price of each unit, representing one share of common stock and a warrant to purchase 0.4 shares of common stock at $1.80 per share, was $0.90. The warrants have a term of five years. The placement agent received placement fees of 8%, in cash or warrants or a combination thereof at their election. As of December 31, 2014 units representing $6,744,000 had been sold, representing 7,493,339 shares of common stock and warrants to purchase 2,997,333 shares of common stock. The placement agent fees related to these units as of December 31, 2014 were cash fees of $338,940 and warrants to purchase 193,380 shares of common stock at $0.01 per share. In addition, the Company incurred legal fees of $10,000 with respect to the private placement.
On January 2, 2014 we issued a total of 550,000 shares to three individuals in connection with amended employment and consulting agreements. Stock based compensation had already been expensed for 150,000 shares as discussed below. The remaining 400,000 shares vest on January 1, 2015, were originally valued at $436,000 based on closing prices of $1.00 for 200,000 shares and $1.18 for 200,000 shares. 200,000 of the shares, issued pursuant to a consulting agreement, were revalued from $236,000 to $138,000 as of December 31, 2014, based on a closing price of $0.32. The stock based compensation related to the 400,000 shares was expensed in 2014.
On June 5, 2014 we issued a total of 600,000 non-qualified stock options to two employees and a consultant, exercisable at $0.8925 per share, with a Black-Scholes value of $629,714 and an expiration date of June 4, 2024. Variables used in the valuation include (1) discount rate of 0.85%, (2) expected life of 5 years for employees and 10 years for the consultant, (3) expected volatility of 220.0% and 219.0% for employees and consultant, respectively, and (4) zero expected dividends. These options were fully vested as of the grant date.
On September 8, 2014 we issued a total of 200,000 non-qualified stock options to a consultant, exercisable at $0.96 per share, with a Black-Scholes value of $173,906 and an expiration date of September 8, 2024. Variables used in the valuation include (1) discount rate of 0.85%, (2) expected life of 10 years, (3) expected volatility of 219.0%, and (4) zero expected dividends. These options were fully vested as of the grant date.
On June 7, 2013, we issued a total of 10,000 shares which vested immediately to two consultants for services rendered with a fair value of $12,000, or $1.20 per share.
On January 2, 2013 we issued 400,000 shares which vested immediately to two employees with a fair value of $364,000, or $0.91 per share.
On August 1, 2012, in connection with a three-year employment agreement, we agreed to issue 150,000 shares of common stock at future dates as specified in the agreement. The agreement specified that we would 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 were to be expensed over the three years of the employment agreement. Pursuant to an amendment to this agreement, the 150,000 shares were issued and immediately vested in early January 2014, and accordingly we recognized the remaining stock-based compensation expense of $152,418 in the year ended December 31, 2013.
Warrants
During the three months ended March 31, 2014, 200,000 warrants were exercised by a consultant who had previously received the warrants in exchange for services.
In addition to the warrants issued pursuant to the private placement discussed above, on April 10, 2014 we issued a warrant to purchase 2,000,000 shares of common stock to a consultant, exercisable at $1.04 per share, with a Black-Scholes value of $2,184,538 and an expiration date of April 9, 2017. Variables used in the valuation include (1) discount rate of 0.81%, (2) expected life of 3 years, (3) expected volatility of 223.0% and (4) zero expected dividends. This warrant was fully vested as of the grant date. This consultant, who acts as project manager for the Company’s drilling operations, is president and a shareholder of an entity which holds stock in the Company and participating in certain of the Company’s wells.
Total stock-based compensation expense was $3,252,158 and $528,418 for the years ended December 31, 2014 and 2013, respectively. All stock-based compensation expense is included in general and administrative expenses in the accompanying consolidated financial statements.
4. SEGMENT AND GEOGRAPHICAL INFORMATION
At December 31, 2014, the Company’s continuing operations comprised one segment in one geographic region.
5. OIL AND GAS PROPERTIES
Oil and gas properties consisted of the following as of December 31, 2014 and 2013:
Depreciation and depletion expense for oil and gas properties totaled $6,690,066 and $2,308,064 in 2014 and 2013, respectively. We also recorded an impairment charge of $29,858,178 in 2014.
On April 21, 2011, the Company entered into a participation agreement (“Participation Agreement”) with Slawson Exploration Company (“Slawson”) and U.S. Energy Development Corporation (“USE,” Slawson and USE, together, the “Parties”). Pursuant to the terms of the Participation Agreement, Slawson and USE acquired 45% and 30% respectively, of our 10,000 acre Nemaha Ridge prospect in Logan County, Oklahoma for $4,875,000. In addition, the Parties carried Osage for 7.5% of the cost of the first three horizontal Mississippian wells, which means that for the first three horizontal Mississippian wells, the Company provided up to 17.5% of the total well costs. After the first three wells, the Company was responsible for up to 25% of the total well costs. Revenue from wells drilled pursuant to the Participation Agreement, after royalty and third party acreage interest payments, was allocated 45% to Slawson, 30% to USE and 25% to Osage. Slawson was the operator of all wells in the Nemaha Ridge prospect in sections where the Parties’ acreage controlled the section. In sections where the Parties’ acreage did not control the section, we may elect to participate in wells operated by others.
On December 12, 2013, Osage and Slawson entered into an agreement (the “Partition Agreement”) related to certain lands located within the Nemaha Ridge in Logan County, Oklahoma, and for the exploration and development of those leases by the Parties.
Under the Partition Agreement and effective as of September 1, 2013, the Slawson Exploration Group agreed to assign all of its rights, title and interest in and to the oil and gas leases and force-pooled acreage which are part of the Nemaha Ridge Project within certain sections to Osage and Osage agreed to assign all of its rights, title and interest in and to the oil and gas leases and force-pooled acreage which are part of the Nemaha Ridge Project within certain sections to the Slawson Exploration Group, such that the net acreage controlled by the parties would remain substantially unchanged, but that the acreage controlled by each of the parties in undeveloped sections would be located in sections where the other party did not control acreage. The parties also agreed that the Participation Agreement would terminate as to all lands within the Nemaha Ridge Project except for lands within sections already developed by the parties which shall continue to be controlled by the Participation Agreement.
In September 2014, Slawson sold its interests in its oil and gas properties in Logan County, Oklahoma to Stephens Energy Group, LLC and Stephens Production Company (collectively “Stephens”).
As a result of the Partition Agreement, Osage has become the project operator on much of its acreage in the Nemaha Ridge Project. As of December 31, 2014, Osage operated or has the right to operate approximately 4,675 net acres (6,967 gross), and remains joint-venture or potential joint-venture partners with others in approximately 5,032 net acres (31,772 gross).
In 2011, we also began to acquire leases in Coal County, Oklahoma, targeting the Woodford Shale formation. The Woodford Shale formation is located mainly in southeastern Oklahoma in the Arkoma Basin. The Woodford shale lies directly under the Mississippian and started as a vertical play, but horizontal drilling techniques and multi-stage fracturing technology have been used in the Woodford in recent years with much success. At December 31, 2014, we had 4,367 net (10,106 gross) acres leased in Coal County.
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. Subsequently, B&W shall have an option to purchase a 12.5% share of leasehold acquired on a heads-up basis. As of December 31, 2014, the Company had 3,934 net acres (5,085 gross) leased in Pawnee County.
At December 31, 2014, we have leased 18,008 net (53,930 gross) acres across three counties in Oklahoma as follows:
6. DEBT
Apollo - Note Purchase Agreement
On April 27, 2012, we entered into a $10,000,000 senior secured note purchase agreement (“Note Purchase Agreement” or “Notes”) with Apollo Investment Corporation (“Apollo”). The Notes, which mature on April 27, 2015, are secured by substantially all of the assets of the Company, including a mortgage on all our Oklahoma leases. The Notes bear interest of Libor plus 15.0% with a Libor floor of 2.0%, with interest payable monthly. In addition, Apollo received a warrant to purchase 1,496,843 shares of common stock, exercisable at $0.01 per share, with a Black-Scholes value of $2,483,952 and an expiration date of April 27, 2017. Variables used in the valuation include (1) discount rate of 0.82%, (2) expected life of 5 years, (3) expected volatility of 245.0% and (4) zero expected dividends. The minimum draw amount on the Note Purchase Agreement is $1,000,000. At closing, we did not draw down any funds. In the year ended December 31, 2013, we drew down $17,000,000 and, as of December 31, 2013, the amount outstanding under the Note Purchase Agreement was $20,000,000.
At closing of the Note Purchase Agreement, we paid $100,000 of a minimum placement fee to CC Natural Resource Partners, LLC (“CCNRP”) and issued a warrant to purchase 250,000 shares of common stock, exercisable at $0.01 per share, with a Black-Scholes value of $413,690 and an expiration date of April 27, 2014. Variables used in the valuation include (1) discount rate of 0.26%, (2) expected life of 2 years, (3) expected volatility of 242.0% and (4) zero expected dividends. In addition, we paid $170,692 in legal fees, of which $100,000 were paid to Apollo. In December 2012, we paid an additional $380,000 in placement fees. We also issued a warrant to purchase 100,000 shares of common stock, exercisable at $0.01 per share, with a Black-Scholes value of $89,952 and a term of five years, to the placement agent for the Note Purchase Agreement and amended the term of the warrant granted on April 27, 2012 from two to five years, with a Black-Scholes value of $1,161. Variables used in the valuation include (1) discount rate of 0.72%, (2) expected life of five years, (3) expected volatility of 242.0% and (4) zero expected dividends. In December 2013 we paid an additional $100,000 in placement fees.
On April 5, 2013 the Company and Apollo amended the Note Purchase Agreement, increasing the amount of the facility to $20,000,000 and modifying certain covenants for the remainder of the Note Purchase Agreement term. The amendment also provided a waiver of certain covenants as of March 31, 2013, as the Company did not meet certain covenants including the minimum production covenant as of that date. The Company paid an amendment fee of $100,000 which is being amortized over the remaining term of the Note Purchase Agreement.
On August 12, 2013, the Company and Apollo amended the Note Purchase Agreement. The amendment required that the Company, within 75 days of the effective date as defined in the amendment, complete either (1) a sale of certain assets, or (2) the issuance of capital stock in a transaction that resulted in aggregate net proceeds as defined in the amendment. In the event that the Company did not complete either one of the aforementioned transactions, the Company would have been required under the terms of the amendment to issue to Apollo additional warrants equivalent to three percent of the Company’s common stock, on a fully-diluted basis. On October 7, 2013 the Company completed the sale of its membership interests in Cimarrona LLC as more fully discussed in Note 13. This sale satisfied the requirements of the amendment and the Company is thus not obligated to issue additional Warrants to Apollo.
On April 3, 2014, the Company and Apollo amended the Note Purchase Agreement, increasing the amount of the total facility to $30,000,000, extending the term by one year and reducing the interest rate from Libor plus 15% to Libor plus 11%. During the nine months ended September 30, 2014, we drew down $5,000,000 of additional funds and, as of December 31, 2014, the amount outstanding under the Note Purchase Agreement was $25,000,000.
The Company has recorded deferred financing costs in the aggregate amount of $3,959,448 in connection with the Note Purchase Agreement, which represented the fair value of warrants issued to Apollo and CCNRP, placement fees, amendment fees and legal fees, which are amortized on a straight-line basis over the term of the Notes, which approximates the effective interest method, as the Company did not draw funds at issuance.
On each anniversary of the closing date, the Company is obligated to pay an administrative fee of $50,000. The Company is 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 three months of interest payments.
The Company is subject to various affirmative, negative and financial covenants under the Note Purchase Agreement as amended along with other restrictions and requirements, all as defined in the Note Purchase Agreement. Affirmative covenants include by October 31st of each year beginning in 2012, a reserve report prepared as of the immediately preceding September 30, concerning the Company’s domestic oil and gas properties prepared by approved petroleum engineers, and thereafter as of September 30th of each year.
The Company and Apollo are negotiating new covenants to the Note Purchase Agreement. Until these negotiations are complete existing covenants, some of which the Company is not in compliance with, remain in place. Accordingly, the Company has classified borrowings under the Note Purchase Agreement as short term in the accompanying consolidated balance sheets.
Use of proceeds is limited to those purposes specified in the Note Purchase Agreement. The Notes are subject to mandatory prepayment in the event of certain asset sales, insurance or condemnation proceeds, issuance of indebtedness, extraordinary receipts and tax refunds. All terms are as defined in the Note Purchase Agreement.
In the year ended December 31, 2014, we drew down $5,000,000 and, as of December 31, 2014, the amount outstanding under the Note Purchase Agreement was $25,000,000.
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 had a maturity date of April 17, 2014 and bore interest of 18%, payable monthly. In addition, Boothbay received 400,000 shares for which the relative fair value of $386,545 was recorded as debt discount, a 1.5% overriding royalty on our leases in section 29, township 17 North, range 3 and a 1.7143% overriding royalty on our leases in section 36, township 19 North, range 4 West in Logan County, Oklahoma. The closing price of the Company’s common stock on April 17, 2012 was $1.14. The Secured Promissory Note was 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. The Company repaid the Secured Promissory Note in full in December 2013.
In connection with the Note Purchase Agreement and certain capital leases, the Company recognized $4,468,568 of interest expense, of which $3,549,086 was cash interest expense, for the year ended December 31, 2014. In connection with the Note Purchase Agreement, Secured Promissory Note and certain terms of the Partition Agreement with Slawson, the Company recognized $4,566,246 of interest expense, of which $2,999,838 was cash interest expense, for the year ended December 31, 2013.
7. DERIVATIVE FINANCIAL INSTRUMENTS
The Company entered into certain derivative financial instruments with respect to a portion of its oil and gas production. These instruments are used to manage the inherent uncertainty of future revenues due to commodity price volatility and currently include only costless price collars. The Company does not intend to hold or issue derivative financial instruments for speculative trading purposes and has elected not to designate any of its derivative instruments for hedge accounting treatment.
As of December 31, 2014, the Company had the following open oil derivative positions. These oil derivatives settle against the average of the daily settlement prices for the WTI first traded contract month on the New York Mercantile Exchange (“NYMEX”) for each successive day of the calculation period.
As of December 31, 2014, the Company had the following open natural gas derivative positions. These natural gas derivatives settle against the NYMEX Penultimate for the calculation period.
Cash settlements and unrealized gains and losses on fair value changes associated with the Company’s commodity derivatives are presented in the “Oil and gas derivatives’ caption in the accompanying consolidated statements of earnings.
The following table sets forth the cash settlements and unrealized gains and losses on fair value changes for commodity derivatives for the years ended December 31, 2014 and 2013.
8. COMMITMENTS AND CONTINGENCIES
ENVIRONMENT
Osage, as owner and operator of oil and gas fields, 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, 2014, 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.
RENTALS AND OPERATING LEASES
In February 2011, the Company entered into a 36 month lease for its corporate offices in San Diego. In February 2014 the Company amended this lease to extend the term for an additional three years through February 2017. In February 2012, the Company entered into a 24 month lease for a vehicle to be utilized by its operations in Oklahoma. In December 2013, the Company entered into a three year lease for office space in Oklahoma City, and also entered into certain equipment leases for furniture and office equipment at that location.
Rental expense totaled $163,401 and $58,147 in 2014 and 2013, respectively.
Future minimum commitments under operating leases are as follows as of December 31, 2014:
CAPITAL LEASES
The Company entered into a lease for certain office furniture and equipment in the first quarter of 2014. The term of the lease is three years and as the lease essentially transfers the risks of ownership it is being accounted for as a capital lease.
Leased property under capital leases at December 31, 2014 includes:
Total depreciation expense under capital leases was $21,240 for the year ended December 31, 2014 and as of that date the future minimum lease payments under capital leases were as follows:
LEGAL PROCEEDINGS
The Company has initiated litigation against Stephen’s with respect to their right to operate 22 wells in which we have a working interest as we contend that we should be the operator. The Company is not a party to any other litigation that has arisen in the normal course of its business or that of its subsidiaries.
SALE OF CIMARRONA LLC
The Cimarrona property is subject to an Ecopetrol Association Contract (the “Association Contract”) whereby Ecopetrol S.A. (“Ecopetrol”) receives royalties of 20% of the oil produced. The pipeline is not subject to the Association Contract. In addition to the royalty, according to the Association Contract, Ecopetrol may, for no consideration, become a 50% partner, once an audit of revenues and expenses indicate that the partners in the Association Contract have received a 200% reimbursement of all historical costs to develop and operate the Guaduas field. If such an audit determines that the specified reimbursement of historical costs occurred prior to September 30, 2013, the Company is required to reimburse Raven for any amounts due to Ecopetrol from Cimarrona LLC which relate to the period prior to that date. The Company believes its maximum exposure is 50% of Cimarrona LLC’s oil revenues for the nine months ended September 30, 2013, or $729,308. The Company has not recorded any provision for this matter, as it is not possible to estimate the potential liability, if any.
9. DILUTIVE SECURITIES
As of December 31, 2014 and 2013, the Company had outstanding dilutive securities, consisting of warrants and options. Changes in warrants and options outstanding are as follows:
Warrants
The intrinsic value of these warrants as of December 31, 2014 was $523,969. The intrinsic value of warrants exercised during 2014 was $226,000. The weighted average grant date fair value for warrants issued in 2014 was $1.03.
Options
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. The first grants under this plan took place in 2014, and are presented below.
These options had no intrinsic value as of December 31, 2014. The weighted average grant date fair value of these options was $1.00.
On June 5, 2014 we issued a total of 600,000 non-qualified stock options to two employees and a consultant, exercisable at $0.8925 per share, with a Black-Scholes value of $629,714 and an expiration date of June 4, 2024. Variables used in the valuation include (1) discount rate of 0.85%, (2) expected life of 5 years for employees and 10 years for the consultant, (3) expected volatility of 220.0% and 219.0% for employees and consultant, respectively, and (4) zero expected dividends. These options were fully vested as of the grant date.
On September 8, 2014 we issued a total of 200,000 non-qualified stock options to a consultant, exercisable at $0.96 per share, with a Black- Scholes value of $173,906 and an expiration date of September 8, 2024. Variables used in the valuation include (1) discount rate of 0.85%, (2) expected life of 10 years, (3) expected volatility of 219.0%, and (4) zero expected dividends. These options were fully vested as of the grant date.
All stock based compensation is reflected in general and administrative expenses in the consolidated financial statements for 2014 and 2013.
Definitions
Expected Dividends-The Company has never declared or paid dividends on common stock and has no plans to do so.
Expected Volatility-Volatility is a measure of the amount by which a financial variable such as a share price has fluctuated or is expected to fluctuate during a period. The Company considered the historical volatility of its share price and business and economic considerations in order to estimate the expected volatility.
Discount Rate-This is the U.S. Treasury rate for the day of each option grant having a term that most closely resembles the expected life of the option.
Expected Life-This is the period of time that the options granted are expected to remain unexercised. Options granted during the year have a maximum contractual term of ten years. The Company estimates the expected life of the option term based on the simplified method as defined in Staff Accounting Bulletin 110. For non-employee options granted, this is the remaining contractual term of the option as of the reporting date.
10. INCOME TAXES
The total provision for income taxes consists of the following in 2014 and 2013:
Following is a reconciliation of the Federal statutory rate to the effective income tax rate for 2014 and 2013:
At December 31, 2014, the Company had federal and state net operating loss carry forwards of approximately $11.8 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, 2014 and December 31, 2013:
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.
11. MAJOR CUSTOMERS AND VENDORS
During 2014 and 2013, the following customers accounted for all of the Company’s sales from continuing operations:
During 2014, we purchased products or services of $9,667,450 from Weatherford US, LP and $6,105,859 from Nabors Drilling, LP, representing 17.5% and 11.1% of total purchases, respectively. In 2013, no vendor represented more than 10% of purchases.
12. 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, 2014 and 2013, 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:
13. DISCONTINUED OPERATIONS
On October 7, 2013, the Company completed the sale of 100% of the membership interests in Cimarrona LLC to Raven, pursuant to the Agreement dated September 30, 2013 by and between the Company and Raven. Cimarrona LLC is the owner of a 9.4% interest in certain oil and gas assets including a pipeline in the Guaduas field, located in the Dindal and Rio Seco Blocks that covers 30,665 acres in the Middle Magdalena Valley in Colombia.
The sales price consisted of cash of $6,550,000 exclusive of escrow, less settlement of debt of Cimarrona LLC of approximately $250,000. $250,000 was to be held in escrow for 12 months to secure any post-Closing purchase price adjustments and any indemnity obligations of the Company pursuant to the Agreement. In addition, so long as the per barrel transportation rate charged with respect to the pipeline was not adjusted prior to March 31, 2014, then Raven was obligated to pay the Company an additional $1,000,000 in cash. Pursuant to the Agreement, the Company also recognized a receivable for a working capital adjustment of $422,955 in other current assets as of December 31, 2013 and recognized a gain on disposal of discontinued operations of $4,873,660 in the year ended December 31, 2013. Raven has reimbursed the Company for the working capital adjustment. On August 31, 2014 the Company and Raven entered into a settlement agreement, due to numerous uncertainties, whereby the escrow was released to Raven and whereby no additional cash is payable by Raven to the Company.
The following table sets forth the results of operations for the discontinued operations for the periods presented:
The Cimarrona property is subject to an Ecopetrol Association Contract (the “Association Contract”) whereby Ecopetrol S.A. (“Ecopetrol”) receives royalties of 20% of the oil produced. The pipeline is not subject to the Association Contract. In addition to the royalty, according to the Association Contract, Ecopetrol may, for no consideration, become a 50% partner, once an audit of revenues and expenses indicate that the partners in the Association Contract have received a 200% reimbursement of all historical costs to develop and operate the Guaduas field. If such an audit determines that the specified reimbursement of historical costs occurred prior to September 30, 2013, the Company is required to reimburse Raven for any amounts due to Ecopetrol from Cimarrona LLC which relate to the period prior to that date. The Company believes its maximum exposure is 50% of Cimarrona LLC’s oil revenues for the nine months ended September 30, 2013, or $729,308. The Company has not recorded any provision for this matter, as it is not possible to estimate the potential liability, if any.
14. SUBSEQUENT EVENTS
None.
15. SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
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 this 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 independently 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. 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. The technical person primarily responsible for audit of our reserve estimates at Pinnacle 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. Pinnacle is an independent firm of petroleum engineers, geologists, geophysicists, and petro physicists; they do not own an interest in our properties and are not employed on a contingent fee basis. Reserve estimates are imprecise and subjective and may change at any time as additional information becomes available. Furthermore, estimates of oil and gas reserves are projections based on engineering data. There are uncertainties inherent in the interpretation of this data as well as the projection of future rates of production. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.
Pinnacle prepared reserve estimates for the year end reports for 2014 and 2013 for our continuing operations in Logan County, Oklahoma. For wells on production with sufficient historical data, remaining reserves were determined by decline curve analysis. For wells with limited production or pressure data history and those with definable reserves using offset well and reservoir parameters, remaining reserves were estimated based on analogy well and test data and other available geological and engineering information.
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 arrangements, but not on escalations based on 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 or 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 from continuing operations are located in the United States.
The aggregate amount of capitalized costs relating to oil and gas producing activities and the related accumulated depletion, depreciation, amortization and valuation allowances as of December 31, 2014 and 2013 are as follows:
Estimated quantities of proved developed and undeveloped reserves of crude oil, natural gas and natural gas liquids, as well as changes in proved developed and undeveloped reserves for our continuing operations during the past two years are indicated below.
All changes in estimated proved developed and proved undeveloped reserves during 2014 and 2013 were as a result of extensions and discoveries.
In December 2011, the Company commenced drilling its first well in Logan County and at December 31, 2014 the Company had commenced drilling 58 gross development wells, 54 of which achieved production and revenues as of December 31, 2014 and two of which were gross dry development wells. During 2014, we participated in drilling 14 gross productive development wells (2.7 net wells), two gross dry development wells (1.8 net wells) and two gross development wells (0.4 net wells) which had not yet achieved production and revenues as of December 31, 2014. During 2013, we participated in the drilling of 35 gross productive wells (6.1 net wells) and 2 gross wells (0.3 net wells) which had not yet achieved production and revenues as of December 31, 2013. During 2012, we participated in the drilling of 5 gross productive wells (1.1 net wells) and 3 gross wells (0.6 net wells) which had not yet achieved production as of December 31, 2012. Also as of December 31, 2014, the Company had completed six gross salt water disposal wells.
The foregoing estimates have been prepared by Pinnacle for the Logan County, Oklahoma property. 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.
Depletion, depreciation and accretion per equivalent unit of production was $31.56 and $22.00 for 2014 and 2013, respectively.
FASB ASC Topic 932, “Disclosure 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.
Cost incurred, both capitalized and expensed, for oil and gas property acquisition, exploration and development for the years ended December 31, 2014 and 2013 were are follows:
Future cash inflows were computed by applying the 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 the continuation of existing economic conditions.
The average prices used in the reserve estimate for oil were $94.99 per BBL in 2014 and $96.94 per BBL in 2013. For natural gas, the average prices used in the reserve estimate were $4.35 per Mcf in 2014 and $3.67 per Mcf in 2013.
Future income tax expenses were computed by applying statutory income tax rates to the difference between pretax net cash flows related 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 2014 and 2013.
The principal changes in the standardized measure of discounted future net cash flows during 2014 and 2013 were as follows: