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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 10-K

 

xANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2011

 

Or

 

¨TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934

 

Commission File #333-74638

ADINO ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

 

MONTANA   82-0369233
(State or other jurisdiction of incorporation)   (IRS Employer Identification Number)
     
2500 CITY WEST BOULEVARD, SUITE 300   HOUSTON, TEXAS   77042
(Address of principal executive offices)   (Zip Code)

 

(281) 209-9800

(Registrant's telephone number, including area code)

 

Securities registered pursuant to Section 12(g) of the Act:

 

Common stock, $0.001 par value per share

 

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

 

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

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   x   Yes     ¨   No

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  ¨ Yes     x   No

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨   Yes     x   No

 

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

 

Large accelerated filer ¨ Accelerated filer ¨
       
Non-accelerated filer ¨ Smaller reporting company x
(Do not check if smaller reporting company)

 

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

 

Yes          ¨  No          x

 

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently competed second fiscal quarter: At June 30, 2011, the market price of all voting and non-voting common equity held by non-affiliates by reference to the closing price of the Company’s stock on such date was $3,962,083.

 

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date:  At April 16, 2012, there were 135,487,043 shares of common stock outstanding.

 

 
 

 

TABLE OF CONTENTS

 

   

Page

No.

PART I
Item 1. Business 4
Item 2. Properties 8
Item 3. Legal Proceedings 8
     
PART II
     
Item 5 Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 9
Item 6 Selected Financial Data 11
Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations 11
Item 7A Quantitative and Qualitative Disclosures About Market Risk 15
Item 8 Financial Statements and Supplementary Data 16
  Report of Independent Registered Public Accounting Firm 16
  Consolidated Balance Sheets – December 31, 2011 and December 31, 2010 17
  Consolidated Statements of Operations- Years Ended December 31, 2011 and 2010 18
  Consolidated Statement of Changes in Stockholders’ Deficit – Years Ended December 31, 2011 and 2010 19
  Consolidated Statements of Cash Flows- Years Ended December 31, 2011 and 2010 20
  Notes to Consolidated Financial Statements 21
     
Item 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 43
Item 9A Controls and Procedures 43
Item 9B Other Information 44
     
PART III
     
Item 10 Directors, Executive Officers and Corporate Governance 44
Item 11 Executive Compensation 45
Item 12 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 46
Item 13 Certain Relationships and Related Transactions, and Director Independence 47
Item 14 Principal Accounting Fees and Services 47
     
PART IV
     
Item 15 Exhibits, Financial Statement Schedules 48
     
Signatures   48

 

3
 

 

PART I

 

ITEM 1. DESCRIPTION OF BUSINESS

 

ORGANIZATION AND GENERAL INFORMATION ABOUT THE COMPANY

 

Adino Energy Corporation ("Adino", “we” or the "Company"), is an emerging oil and gas exploration and production company focused on mature oilfield assets with significant redevelopment, workover and enhanced oil recovery (EOR) potential. The Company also leases and operates a fuel terminal in Houston, Texas.

 

Adino was incorporated under the laws of the State of Montana on August 13, 1981, under the name Golden Maple Mining and Leaching Company, Inc. In 1985, the Company ceased its mining operations and discontinued all business operations in 1990. The Company then acquired Consolidated Medical Management, Inc. (“CMMI”) and kept the CMMI name. The Company initially focused its efforts on the continuation of the business services offered by CMMI. These services focused on the delivery of turn-key management services for the home health industry, predominately in south Louisiana. The Company exited the medical business in December 2000. In August 2001, the Company decided to refocus on the oil and gas industry. In 2003, we decided to cease our oil and gas activities and focus on becoming a fuel company.

 

The Company’s wholly-owned subsidiary, Intercontinental Fuels, LLC (“IFL”), a Texas limited liability company, was founded in 2003. Adino first acquired 75% of IFL’s membership interests in 2003. The Company acquired 100% ownership of IFL shortly thereafter.

 

In January 2008, the Company changed its name to Adino Energy Corporation. We believe that this name better reflects our current and future business activities, as we plan to continue focusing on the energy industry.

 

As of July 1, 2010, the Company acquired PetroGreen Energy LLC, a Nevada limited liability company, and AACM3, LLC, a Texas limited liability company d/b/a Petro 2000 Exploration Co. (together "Petro Energy"). Petro Energy is a licensed Texas oilfield operator currently operating 11 wells on two leases covering approximately 300 acres in Coleman County, Texas. Petro Energy also owns a drilling rig, two service rigs and associated tools and equipment. The Company also acquired the operator license held by the principal of Petro Energy.

 

After the acquisition of Petro Energy, the Company created two wholly owned subsidiaries:  Adino Exploration, LLC (“Adino Exploration”) and Adino Drilling, LLC (“Adino Drilling”).  All oil and gas leases were transferred from the Petro Energy companies to Adino Exploration and future oil and gas exploration acquisitions and activity are to be operated through this company.  The large drilling rig acquired in the Petro Energy transaction and other associated drilling machinery and equipment were transferred to Adino Drilling.

 

On March 31, 2011, the Company sold the membership shares of Adino Drilling, LLC to a related party.  Under the terms of the agreement, the Company realized a reduction in accrued liability of $100,000 and acquired a $500,000 six year, 5.24% interest note receivable, for a total sale price of $600,000.  The sale resulted in a gain to the Company of $247,376; however the transaction’s related party note of $500,000 is not allowed for reporting purposes, therefore the Company has a reportable loss of $252,624.

 

With the Company’s focus on oil and gas exploration and production, the Company decided to sell its interest in IFL. To that end, on February 7, 2012 (subsequent to the period covered by this report), Adino sold all of its membership interest in IFL to a third party.

 

DESCRIPTION OF BUSINESS

 

Oil and Gas Exploration and Production

 

On July 1, 2010, the Company acquired 100% of the membership interests of Petro Energy for 10,000,000 shares of Adino common stock; however, the newly issued shares will remain in escrow until Adino’s stock price reaches $0.25 per share. If Adino's stock price fails to reach $0.25 within three years, the sellers may repurchase for $1.00 the assets originally held by Petro Energy on July 1, 2010.

 

Petro Energy was a licensed Texas oilfield operator operating 11 wells on two leases covering approximately 300 acres in Coleman County, Texas. Petro also owned a drilling rig, two service rigs and associated tools and equipment. The Company also acquired the operator license held by the principal of PetroGreen and Petro 2000 Exploration Co.

 

The newly acquired leases have mature production from eight proved developed producing (PDP) wells and three saltwater disposal wells. The area has seen active oil production from multiple pay zones since the 1950s. Reservoir pressure has dropped over time; however, the Company believes that significant oil remains in place. Adino started a waterflood project, which management believes will substantially increase both daily production and economically recoverable reserves.

 

4
 

 

Since the acquisition, the Company has completed Phase I of its workover program on its Felix Brandt and Felix Brandt "A" leases (collectively, the “Felix Brandt leases”) located in southeast Coleman County, Texas. With the completion of Phase I of the workover program, Adino has eight wells on production. Two more wells are designated as injection wells for the previously announced waterflood project (one is an active injection well and the other is in the permitting process). The Company also recompleted an existing well as a water source for the waterflood.

 

During Phase I, Adino perforated into new zones on two of the existing wells and applied acid fracture jobs on both. Acid fracture involves pumping a diluted acid solution, under high pressure, into underground formations containing hydrocarbons. The technique is used to improve the permeability of the formations, allowing hydrocarbons to flow more easily into the wellbore.

 

In addition, significant parts of the production equipment have been replaced and water storage tanks have been installed. The Company continues to improve basic infrastructure on the Felix Brandt Leases, including retention berms around the tank batteries, trenching flow-lines and removal of debris from the area.

 

With the initial Petro Energy purchase, the Company acquired 100% of the working interest (87.5% net revenue interest) in the James Leonard lease (the “Leonard lease”) in southeast Coleman County, Texas. The primary target pay zone of the Leonard lease is the Fry Sand at approximately 1,200 feet.

 

In December 2010, we began Phase II of the Petro Energy development plan for the Leonard lease. The Company cleared the needed land and drilled 3 successful wells on the Leonard lease, completing those wells in early summer 2011. We have also moved in the required tank battery with retention berms, put in flow lines and have added a shop for localized equipment repairs and disbursement.

 

With the success of the drilling program, the Company had the reserve analysis recalculated to include both the Felix Brandt and Leonard leases. An independent engineering firm estimated the discounted net cash flow increased from $118,590 as of December 31, 2010 to $951,270 at December 31, 2011.

 

On October 12, 2011, the Company signed a letter of intent with Ashton Oilfield Services, LLC (“Ashton”) for purchase of oilfield equipment, including a drilling rig, associated equipment and several vehicles.  The proposed purchase price for the assets was $6,000,000 in face value of convertible preferred stock of the Company, with the preferred stock converting to common stock at the rate of $0.15 per share. In November 2011, the Company closed on $1,500,000 of the total proposed sale price, issuing 100,000 shares of preferred stock to a limited partnership managed by Ashton. The agreement was finalized in November and the Company began consolidating the equipment from its various locations in Texas, New Mexico and Oklahoma. The Company later decided not to acquire the remaining Ashton assets. On February 7, 2012 (subsequent to the period covered by this report), the Company sold all oilfield machinery and equipment it had purchased from Ashton Oilfield Services in its November 2011 acquisition for $500,000 cash.

 

On October 14, 2011, the Company entered into a production agreement with BlueRock Energy Capital II, LLC (“BlueRock”).  Under the production agreement, BlueRock has agreed to fund Adino with $410,000 for the drilling of five oil wells on the Leonard and Felix Brandt leases and for working capital.  Under the terms of the production agreement, BlueRock will be entitled to 65% of the net revenue interest of the wells until BlueRock receives $410,000 plus an 18% return on investment.  These monies are to be paid as the Company receives production payments on the new wells.  After payment of this amount, BlueRock will receive a 3% overriding royalty interest on the wells.

 

Drilling began on the BlueRock five well program (one well on the Felix Brandt lease and four wells on the Leonard lease) in November 2011. Drilling was completed by December 31, 2011 with well completion expected in 2012.

 

The Company believes that its focused efforts in exploration and production during 2011 were very successful. We plan to continue the path of lease acquisition and development resulting in increased production and reserve interests in 2012 and beyond.

 

Fuel Storage Operations

 

With the Company’s focus on oil and gas exploration and production, the Company decided to sell its interest in IFL. To that end, on February 7, 2012 (subsequent to the period covered by this report), Adino sold all of its membership interest in IFL to Pomisu XXI S.L. (“Buyer”). The purchase price to be paid by the Buyer is $900,000, paid in two installments with the first installment of $244,824.97 paid on February 7, 2012, and the balance due not later than May 7, 2012. The balance of the purchase price shall be computed as follows: $900,000 minus $244,842.97 (initial installment) minus $655,157 of IFL liabilities assumed and settled by the Buyer. The liabilities included $106,520 in accounts payable, $1,500 to a related party, $110,000 in retained customer deposit and $437,155 for the G J Capital lawsuit judgment (see Item 3 for a more thorough discussion).

 

GOVERNMENTAL REGULATIONS / ENVIRONMENTAL MATTERS

 

Proposals and proceedings that might affect the oil and gas industry are periodically presented to Congress and state legislatures and commissions.  We cannot predict when or whether any such proposals may become effective.  The petroleum industry is heavily regulated.  There is no assurance that the regulatory approach currently pursued by various agencies will continue indefinitely.  Notwithstanding the foregoing, we currently do not anticipate that compliance with existing federal, state and local laws, rules and regulations, will have a material or significantly adverse effect upon our capital expenditures, earnings or competitive position.

 

5
 

 

We are subject to various types of regulation at the federal, state and local levels.   This regulation includes requiring permits for drilling wells, maintaining bonding requirements in order to drill or operate wells and regulating the location of wells, the method of drilling and casing of wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells and the disposal of fluids used or generated in connection with operations.  Our operations are also subject to various conservation laws and regulations.  These include the regulation of the size of drilling and spacing units or proration units and the density of wells which may be drilled and the unitization or pooling of oil and natural gas properties.  In addition, state conservation laws sometimes establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production.  The effect of these regulations may limit the amount of oil and natural gas we can produce from our wells in a given state and may limit the number of wells or the locations at which we can drill.

 

Currently, there are no federal, state or local laws that regulate the price for our sales of crude oil, natural gas, natural gas liquids or condensate.  However, the rates charged and terms and conditions for the movement of gas in interstate commerce through certain intrastate pipelines and production area hubs are subject to regulation under the Natural Gas Policy Act of 1978, as amended.  Pipeline and hub construction activities are, to a limited extent, also subject to regulations under the Natural Gas Act of 1938, as amended.  While these controls do not apply directly to us, their effect on natural gas markets can be significant in terms of competition and cost of transportation services, which in turn can have a substantial impact on our profitability and costs of doing business.  Additional proposals and proceedings that might affect the natural gas and crude oil extraction industry are considered from time to time by Congress, and state regulatory bodies.  We cannot predict when or if any such proposals might become effective and their effect, if any, on our operations.  We do not believe that we will be affected by any action taken in any materially different respect from other crude oil and natural gas producers, gatherers and marketers with whom we compete.

 

State regulation of gathering facilities generally includes various safety, environmental and in some circumstances, nondiscriminatory take requirements.  This regulation has not generally been applied against producers and gatherers of natural gas and crude oil to the same extent as processors, although natural gas and crude oil gathering may receive greater regulatory scrutiny in the future.

 

Our oil and natural gas production and saltwater disposal operations and our processing, handling and disposal of hazardous materials, such as hydrocarbons and naturally occurring radioactive materials are subject to stringent environmental regulation.  Compliance with environmental regulations is generally required as a condition to obtaining drilling permits.  State inspectors frequently inspect regulated facilities and review records required to be maintained for document compliance.  We could incur significant costs, including cleanup costs resulting from a release of hazardous material, third-party claims for property damage and personal injuries, fines and sanctions, as a result of any violations or liabilities under environmental or other laws.  Changes in or more stringent enforcement of environmental laws could also result in additional operating costs and capital expenditures.

 

Our operations are also subject to numerous federal, state, and local laws and regulations controlling the generation, use, storage, and discharge of materials into the environment or otherwise relating to the protection of the environment.

 

In the United States, the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as "Superfund," and comparable state statutes impose strict, joint, and several liability on certain classes of persons who are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of a disposal site or sites where a release occurred and companies that generated, disposed or arranged for the disposal of the hazardous substances released at the site. Under CERCLA, such persons or companies may be retroactively liable for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is common for neighboring land owners and other third parties to file claims for personal injury, property damage, and recovery of response costs allegedly caused by the hazardous substances released into the environment. The Resource Conservation and Recovery Act ("RCRA") and comparable state statutes govern the disposal of "solid waste" and "hazardous waste" and authorize imposition of substantial civil and criminal penalties for failing to prevent surface and subsurface pollution, as well as to control the generation, transportation, treatment, storage and disposal of hazardous waste generated by oil and gas operations.

 

Although CERCLA currently contains a "petroleum exclusion" from the definitions of "hazardous substance," state laws affecting our operations impose cleanup liability relating to petroleum and petroleum related products, including crude oil cleanups. In addition, although RCRA regulations currently classify certain oilfield wastes which are uniquely associated with field operations as "non-hazardous," such exploration, development and production wastes could be reclassified by regulation as hazardous wastes, thereby administratively making such wastes subject to more stringent handling and disposal requirements.

 

We currently own or lease, or will own or lease in the future, properties that have been used for the storage of petroleum products. Although we utilize standard industry operating and disposal practices, hydrocarbons or other wastes may be disposed of or released on or under the properties owned or leased by us or on or under other locations where such wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA, and analogous state laws. Our operations are also impacted by regulations governing the disposal of naturally occurring radioactive materials. The Company must comply with the Clean Air Act and comparable state statutes, which prohibit the emissions of air contaminants, although a majority of our activities are exempted under a standard exemption.

 

6
 

 

Federal regulations also require certain owners and operators of facilities that store or otherwise handle oil to prepare and implement spill prevention, control and countermeasure plans and spill response plans relating to possible discharge of oil into surface waters. The federal Oil Pollution Act ("OPA") contains numerous requirements relating to prevention of, reporting of, and response to oil spills into waters of the United States. For facilities that may affect state waters, OPA requires an operator to demonstrate $10 million in financial responsibility. State laws mandate crude oil cleanup programs with respect to contaminated soil.

 

We are not currently involved in any administrative, judicial or legal proceedings arising under domestic or foreign, federal, state, or local environmental protection laws and regulations, or under federal or state common law, which would have a material adverse effect on our financial position or results of operations.

 

EMPLOYEES

 

As of December 31, 2011, Adino and its subsidiaries have one employee. We have consulting and management arrangements with our officers and have outsourced our fuel terminaling operations to minimize payroll expense. We have contracts with 9 persons, including executive officers, non-executive officers, secretarial and field personnel.

 

COMPETITION

 

We face competition from other oil and natural gas companies in all aspects of our business, including acquisition of producing properties and oil and natural gas leases, marketing of oil and natural gas, and obtaining goods, services and labor.  Most of our competitors have substantially larger financial and other resources than the Company.  Factors that affect our ability to acquire producing properties include available funds, available information about prospective properties and our limited number of employees.  Competition is also presented by alternative fuel sources including heating oil and other fossil fuels.  Renewable energy sources may become more competitive in the future.

 

The availability of a ready market for and the price of any hydrocarbons produced will depend on many factors beyond our control including, but not limited to, the amount of domestic production and imports of foreign oil and liquefied natural gas, the marketing of competitive fuels, the proximity and capacity of natural gas pipelines, the availability of transportation and other market facilities, the demand for hydrocarbons, the effect of federal and state regulation of allowable rates of production, taxation, the conduct of drilling operations and federal regulation of crude oil and natural gas.  In addition, the restructuring of the natural gas pipeline industry virtually eliminated the gas purchasing activity of traditional interstate gas transmission pipeline buyers.  Producers of natural gas have therefore been required to develop new markets among gas marketing companies, end users of natural gas and local distribution companies.  All of these factors, together with economic factors in the marketing arena, generally affect the supply of and/or demand for oil and natural gas and thus the prices available for sales of oil and natural gas.

 

FUTURE BUSINESS

 

Oil and Gas Exploration and Production

 

The Company believes that its focused efforts in exploration and production during 2011 were very successful. We plan to continue the path of lease acquisition and development resulting in increased production and reserve interests in 2012 and beyond.

 

Fuel Storage Operations

 

With the Company’s focus on oil and gas exploration and production, the Company decided to sell its interest in IFL. To that end, on February 7, 2012 (subsequent to the period covered by this report), Adino sold all of its membership interest in IFL to Pomisu XXI S.L. (“Buyer”). The purchase price to be paid by the Buyer is $900,000, paid in two installments with the first installment of $244,824.97 paid on February 7, 2012, and the balance due not later than May 7, 2012. The balance of the purchase price shall be computed as follows: $900,000 minus $244,842.97 (initial installment) minus $655,157 of IFL liabilities assumed and settled by the Buyer. The liabilities included $106,520 in accounts payable, $1,500 to a related party, $110,000 in retained customer deposit and $437,155 for the G J Capital lawsuit judgment (see Item 3 for a more thorough discussion).

 

7
 

 

ITEM 2. DESCRIPTION OF PROPERTY

 

Adino Corporate Offices

 

Adino’s executive offices are located at 2500 Citywest Boulevard, Houston, Texas. These premises are leased on a month-to-month basis.

 

Oil and Gas Exploration and Production

 

Adino Exploration, LLC has regional headquarters in Coleman, Texas.  The Company has leased a dual bay warehouse facility with secure yard storage from the Coleman County Economic Development Council. The warehouse includes a reception area, an office and a conference room

 

Fuel Storage Operations

 

IFL’s headquarters are located at its fuel distribution terminal at 17617 Aldine Westfield Road, Houston, Texas. This terminal is leased from Lone Star Fuel Storage and Transfer LLC for $31,855 per month. The terminal is situated on 10 ½ acres adjacent to, and to the west of the George Bush International Airport (IAH). The terminal has 7 fuel storage tanks with a collective capacity of 163,349 barrels of product (6,860,658 gallons). Auxiliary buildings containing 5,800 square feet are present. There are three loading bays for tanker trucks. The terminal is configured to handle 20,000,000 gallons of motor fuel per month through the truck loading racks.  Although not currently connected, a six inch dedicated pipeline connects the terminal to IAH, capable of moving 22,000,000 gallons of jet fuel per month through the pipeline to the airport.

 

Originally built between 1981 and 1988, substantial renovation and improvement was done by two customers in 2000-2001.  Adino’s management team acquired the non-operational terminal in 2003. Adino’s management then brought the terminal up to code, passed all inspections and acquired all licenses necessary for operations.   In March 2006, the terminal opened with its first storage customer, the Metropolitan Transportation Authority of Harris County (Houston’s mass transit authority).  From 2006 to 2008, additional customers were added and substantial improvements were made to the property and facilities.  Security was enhanced and office buildings and grounds were improved.  The loading rack had a third lane added to accommodate additional customer load.  Larger, more efficient pumps were installed and the rack was configured to handle the newly mandated ultra low sulfur diesel.

 

Kerosene, jet fuel, gasoline and diesel oil can be brought to the terminal via TEPPCO and Magellan pipelines. Jet fuel can be provided to IAH via pipeline and by truck to other airports. However, IFL is not currently pursuing the aviation market. Gasoline and diesel fuel are shipped out by tanker truck.

 

The property is not located in a flood hazard area. There are no known soil or subsoil conditions which would adversely affect construction. Private well and septic systems are in place and in sufficient capacity to support the terminal.  Neither functional nor external obsolescence affect the property.

 

As stated earlier, IFL was sold after the period covered by this report, and as a result, as of February 7, 2012, the Company no longer leases the IFL fuel terminal. The purchase price to be paid by the Buyer is $900,000, paid in two installments with the first installment of $244,824.97 paid on February 7, 2012, and the balance due not later than May 7, 2012. The balance of the purchase price shall be computed as follows: $900,000 minus $244,842.97 (initial installment) minus $655,157 of IFL liabilities assumed and settled by the Buyer. The liabilities included $106,520 in accounts payable, $1,500 to a related party, $110,000 in retained customer deposit and $437,155 for the G J Capital lawsuit judgment (see Item 3 for a more thorough discussion).

 

ITEM 3. LEGAL PROCEEDINGS

 

G J Capital, Ltd. v. Adino Energy Corporation, et. al.

 

On March 15, 2010, G J Capital, Ltd. (“G J Capital”) filed suit against Adino Energy Corporation and IFL in the 129th Judicial District Court of Harris County, Texas. G J Capital’s claim relates to a repurchase agreement whereby IFL sold to G J Capital certain assets for $250,000 and retained the ability to repurchase the assets in sixty days by paying to G J Capital the amount of $275,000. G J Capital’s petition alleged claims of breach of contract, money had and received, and fraudulent misrepresentation. G J Capital later amended its petition to allege that certain of Adino’s directors and officers (Mr. Timothy Byrd and Mr. Sonny Wooley) fraudulently transferred assets of Adino and/or IFL. G J Capital has also alleged that Mr. Wooley and Mr. Byrd are the  alter ego of Adino and IFL, and/or that Adino and/or IFL are alter egos of one another. G J Capital also alleged fraudulent conduct by one or more of the defendants.

 

8
 

 

Adino, IFL, Mr. Byrd and Mr. Wooley countersued G J Capital and filed third-party claims against CapNet Securities Corporation (“CapNet”), Daniel L. Ritz, Jr. (“Ritz”), Gulf Coast Fuels, Inc. (“Gulf Coast”) and Paul Groat (“Groat”), alleging that they conspired to damage IFL and Adino by involving it in the transaction described above. In this action, Adino, IFL, Mr. Byrd and Mr. Wooley contended that Ritz, CapNet, Gulf Coast, and Groat were involved together for the common, improper scheme to cause IFL immense financial hardship so that Gulf Coast could acquire the fuel terminal currently leased by IFL at an unfairly low price; that as part of this conspiracy they also effected a settlement of the Gulf Coast claim (which, if true, would mean that G J Capital acquired no claim at all against any of the defendants); and that in addition or in the alternative, even if G J Capital acquired some cognizable interest against IFL, Adino, IFL, Byrd and Wooley are entitled to indemnification by and contribution by Ritz, CapNet, Gulf Coast, and Groat.

 

In December 2011, G J Capital dismissed its claims against Mr. Byrd and Mr. Wooley. Also in December 2011, the court rendered judgment for G J Capital and against Adino and IFL in the amount of $250,000, plus $152,987.50 in attorneys’ fees, $9,300.00 in court costs, plus $20,616.44 in prejudgment interest. Interest will continue to accrue on the judgment at the rate of $34.25 until satisfied. The Company did not appeal this judgment. The Company accrued all fees and interest related to the judgment as of December 31, 2011. The total accrual expensed to IFL was $437,155. This amount was assumed by the buyer of IFL in the February 2012 sale. (See Item 2 and Note 22 for a thorough discussion of the IFL sale and terms).

 

 PART II

 

ITEM 5. MARKET FOR COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

 

As of December 31, 2011, Adino had 125,574,295 shares of common stock outstanding. There are approximately 891 holders of record of our common stock.

 

The Company’s common stock is quoted on the Over-the-Counter Bulletin Board (“OTCBB”) operated by the Financial Industry Regulatory Authority, Inc. and the OTCQB operated by OTC Markets Group, Inc.

 

The following table sets forth certain information as to the high and low bid quotations quoted on the OTCBB and OTCQB for 2010 and 2011. Information with respect to over-the-counter bid quotations represents prices between dealers, does not include retail mark-ups, mark-downs or commissions, and may not necessarily represent actual transactions.

 

Period  High   Low 
Fourth Quarter 2011  $0.05   $0.02 
Third Quarter 2011  $0.038   $0.013 
Second Quarter 2011  $0.038   $0.015 
First Quarter 2011  $0.05   $0.02 
           
Fourth Quarter 2010  $0.055   $0.02 
Third Quarter 2010  $0.07   $0.01 
Second Quarter 2010  $0.02   $0.01 
First Quarter 2010  $0.03   $0.01 

 

The source of the above information is Yahoo Finance and OTCmarkets.com.

 

DIVIDENDS

 

We have not paid any dividends on our common or preferred stock in the past two fiscal years. We presently intend to retain future earnings to support our growth. Any payment of cash dividends in the future will be dependent upon the amount of funds legally available, our earnings, financial condition, capital requirements, and any other factors which our Board of Directors deems relevant.

 

In August 2010, we entered into a convertible promissory note which limits us from paying or declaring a dividend on our common stock.

 

During 2011, the Company authorized two new series of Class B Preferred Stock, Series 1 and Series 3. The Class B Series 1 shares are not entitled to dividend payment. The holders of Class B Preferred Stock Series 3 shall be entitled to receive a quarterly dividend equal to 2.5% of the issue price of each share ($35.00). The dividends shall be paid quarterly, when and if declared payable by the Company’s Board of Directors from funds legally available for the payment thereof. If in any quarter the Company does not pay any accrued dividends, such dividends shall cumulate. Interest shall not be paid on cumulated dividends. Each share of Class B Preferred Stock Series 3 shall rank on the same parity with each other share of preferred stock, irrespective of series, with respect to dividends at the respective fixed or maximum rate for such series.

 

RECENT SALES OF UNREGISTERED SECURITIES

 

On February 2, 2010, the Board approved a stock issuance of 250,000 shares of restricted common stock each to Michael Turchi and Mountaintop Development, Inc. for services rendered to the Company. The issuance resulted in an expense to the Company of $5,700, based on the stock’s market price at the date of issuance.

 

9
 

 

The Company issued 10,000,000 shares of stock to the sellers in the Petro Energy acquisition. The Company acquired 100% of the membership interests of both companies as of July 1, 2010. The transaction resulted in stock expense to the Company of $150,000, based on the stock’s market price at the date of issuance. See Notes 1, 6, 9, 13, and Item 1 for a thorough discussion of the acquisition transaction.

 

On September 7, 2010, the Board approved a stock issuance of 2,000,000 shares of restricted common stock to Vulcan Advisors, LLC for consulting services performed for the Company. The issuance resulted in an expense to the Company of $70,000, based on the stock’s market price at the date of issuance.

 

During November 2010, the Board approved a stock issuance of 500,000 shares each to its three members for services rendered.  The total issuance of 1,500,000 shares resulted in expense to the Company of $46,500, based on the stock’s market price at the date of issuance.

 

On February 22, 2011, Asher converted $10,000 of its note into 465,116 shares of the Company’s common stock. The conversion resulted in an increase of additional paid-in-capital of $9,535 due to the reduction of the associated liability.

 

On March 8, 2011, Asher converted $12,000 of its note into 603,015 shares of the Company’s common stock. The conversion resulted in an increase of additional paid-in-capital of $11,397 due to the reduction of the associated liability.

 

On March 22, 2011, Asher converted $12,000 of its note into 794,702 shares of the Company’s common stock. The conversion resulted in an increase of additional paid-in-capital of $11,205 due to the reduction of the associated liability.

 

On April 4, 2011, Asher converted $15,000 of its note into 1,219,512 shares of the Company’s common stock. The conversion resulted in an increase of additional paid-in-capital of $13,780 due to the reduction of the associated liability.

 

On April 12, 2011, Asher converted $8,500 of its note into 817,308 shares of the Company’s common stock. The conversion resulted in an increase of additional paid-in-capital of $7,683 due to the reduction of the associated liability.

 

During the fourth quarter 2011, Asher converted $48,000 of its notes into 2,664,063 shares of the Company’s common stock. The conversions resulted in an increase of additional paid-in-capital of $45,336 due to the reduction of the associated liability.

 

All of the above note conversions were within the terms of the agreement. The Company claims an exemption under Section 4(2) of the Securities Act for the issuance of each promissory note. The Company claims an exemption under Section 3(a)(9) of the Securities Act for the issuances of common stock pursuant to each note conversion.

 

On August 9, 2011, the Company entered into a consulting agreement with RKM Capital for consulting and investor relations services.  The Company paid $2,500 and issued ten million, seven hundred fifty thousand (10,750,000) shares of restricted common stock, with a market price of $0.02 per share, resulting in expense to the Company of $225,750. The Company claims an exemption under Section 4(2) of the Securities Act for this issuance.

 

On September 16, 2011, the Board of Directors issued 250,000 shares of restricted common stock to each of its directors as compensation for 2011 director’s fees.  The market price on date of the grant was $0.022, resulting in expense to the Company of $11,000. The Company claims an exemption under Section 4(2) of the Securities Act for this issuance.

 

On September 16, 2011, the Company granted 500,000 shares of restricted common stock to the Company’s controller, Nancy Finney, for services rendered.  Ms. Finney relinquished the 500,000 fully vested options granted to her in 2007 with this transaction. The Company claims an exemption for the above issuance pursuant to Section 3(a)(9) of the Securities Act due to the fact that Ms. Finney was an existing security holder of the Company at the time of the exchange.

 

In November 2011, the Company agreed to issue 95,534 shares of Class “B” Preferred Stock Series 1 ( “Preferred Stock”) to AOS 1A, LP (“Shareholder”) pursuant to an Asset Purchase Agreement entered into by the Company whereby the Company purchased all the unencumbered assets of AOS 1A, LP. The Preferred Stock is convertible into common stock at the Shareholder’s option at any time after six months, provided that (a) immediately after the first six months, only 25% of the Preferred Stock may be converted to common stock, and (b) each month thereafter, only up to 12.5% of the Preferred Stock may be converted to common stock. These shares were issued on January 7, 2012, subsequent to the period covered by this report. The Company claims an exemption under Section 4(2) of the Securities Act for this issuance.

 

In November 2011, the Company agreed to issue 4,466 shares of Class “B” Preferred Stock Series 1 (“Preferred Stock”) to AOS 1-B, LP pursuant to an Asset Purchase Agreement entered into by the Company whereby the Company purchased all the unencumbered assets of AOS 1-B, LP. The Preferred Stock shall be convertible into common shares at Shareholder’s option at any time after six months, provided that (a) (b) immediately after the first six months, only 25% of the Preferred Stock may be converted to common stock, and (b) each month thereafter, only up to 12.5% of the Preferred Stock may be converted to common stock. These shares were issued on January 7, 2012, subsequent to the period covered by this report. The Company claims an exemption under Section 4(2) of the Securities Act for this issuance.

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PART II

 

ITEM 6. SELECTED FINANCIAL DATA

 

Item 6 is not required for a smaller reporting company.

 

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

The following is a discussion of our financial condition, results of operations, liquidity and capital resources. This discussion should be read in conjunction with our Consolidated Financial Statements and the notes thereto included elsewhere in this Form 10-K.

 

FORWARD-LOOKING INFORMATION

 

This report contains a number of forward-looking statements, which reflect the Company's current views with respect to future events and financial performance including statements regarding the Company's projections. These forward-looking statements are subject to certain risks and uncertainties that could cause actual results to differ materially from historical results or those anticipated. In this report, the words "anticipates", "believes", "expects", "intends", "future", "plans", "targets" and similar expressions identify forward-looking statements. Readers are cautioned to not place undue reliance on the forward-looking statements contained herein, which speak only as of the date hereof. The Company undertakes no obligation to publicly revise these forward-looking statements, to reflect events or circumstances that may arise after the date hereof. Additionally, these statements are based on certain assumptions that may prove to be erroneous and are subject to certain risks including, but not limited to, the Company's dependence on limited cash resources, and its dependence on certain key personnel within the Company. Accordingly, actual results may differ, possibly materially, from the predictions contained herein.

 

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

 

The Company's discussion and analysis of its financial condition and results of operations are based upon its consolidated financial statements, which have been prepared in accordance with generally accepted accounting principles in the United States. The preparation of these financial statements requires the Company to make estimates and judgments that affect the reported amounts of assets, liabilities, revenue and expenses, and related disclosure of contingent assets and liabilities. The Company evaluates its estimates on an ongoing basis. The Company bases its estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances. These estimates and assumptions provide a basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions, and these differences may be material.

 

Consolidation

The accompanying financial statements include the accounts of Adino Energy Corporation and its wholly owned subsidiaries Intercontinental Fuels, LLC, Adino Exploration, LLC, Adino Drilling, LLC (sold 3/1/2011), PetroGreen Energy LLC, and AACM3, LLC.  All intercompany accounts and transactions have been eliminated. References to Adino or the Company include the above subsidiaries.

 

Revenue Recognition

IFL earns revenue from both throughput and storage fees on a monthly basis. The Company recognizes revenue from throughput fees in the month that the services are provided based upon contractually determined rates. The Company recognizes storage fee revenue in the month that the service is provided in accordance with our customer contracts.  Adino Exploration earns revenue from the sale of oil.

 

As described above, in accordance with the requirement of current guidance, the Company recognizes revenue when (1) persuasive evidence of an arrangement exists (contracts) (2) delivery has occurred (monthly) (3) the seller’s price is fixed or determinable (per the customer’s contract or current market price) and (4) collectability is reasonably assured (based upon our credit policy).

 

The Company has performed an analysis and determined that gross revenue reporting is appropriate, since (1) the Company is the primary obligor in the transaction (2) the Company has latitude in establishing price and (3) the Company changes the product and performs part of the service.

 

Investments

The Company from time to time maintains a portfolio of marketable investment securities for deposit requirements associated with our oil and gas operator licenses. The securities have an investment grade and a term to earliest maturity generally of ten months to over one year and include certificates of deposit. These securities are carried at cost, which approximates market. The Company’s securities are classified as held-to-maturity because the Company has the positive intent and ability to hold the securities to maturity.

 

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Oil and Gas Producing Activities 

The Company follows the full cost method of accounting for oil and gas operations whereby all costs associated with the exploration and development of oil and gas properties are initially capitalized into a single cost center (“full cost pool”). Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties and costs of drilling directly related to acquisition and exploration activities. Proceeds from property sales are generally credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 25% or more of the proved reserves related to a full cost pool.

 

Depletion of exploration and production costs and depreciation of production equipment is computed using the units of production method based upon estimated proved oil and gas reserves as determined by consulting engineers and prepared (annually) by independent petroleum engineers. Costs included in the depletion base to be amortized include (a) all proved capitalized costs including capitalized asset retirement costs, net of estimated salvage values, less accumulated depletion, (b) estimated future development cost to be incurred in developing proved reserves; and (c) estimated dismantlement and abandonment costs, net of estimated salvage values that have not been included as capitalized costs because they have not yet been capitalized in asset retirement costs. The costs of unproved properties are withheld from the depletion base until it is determined whether or not proved reserves can be assigned to the properties. The unproved properties are reviewed quarterly for impairment. When proved reserves are assigned or the unproved property is considered to be impaired, the cost of the property or the amount of the impairment is added to the costs subject to depletion calculations.

 

Derivatives

The Company does not use derivative instruments to hedge exposures to cash flow, market, or foreign currency risks. Derivative financial instruments are initially measured at their fair value. For derivative financial instruments that are accounted for as liabilities, the derivative instrument is initially recorded at its fair value and is then revalued at each reporting date, with changes in the fair value reported as charges or credits to income. For option−based derivative financial instruments, the Company uses the Lattice model to value the derivative instruments. The classification of derivative instruments, including whether such instruments should be recorded as liabilities or as equity, is reassessed at the end of each reporting period. Derivative instrument liabilities are classified in the balance sheet as current or non−current based on whether or not cash settlement of the derivative instrument could be required within 12 months of the balance sheet date.

 

Asset Retirement Obligation

The Company accounts for its asset retirement obligations by recording the fair value of a liability for an asset retirement obligation recognized for the period in which it was incurred if a reasonable estimate of fair value could be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The increase in carrying value of a property associated with the capitalization of an asset retirement cost is included in proved oil and gas properties in the consolidated balance sheets. The Company depletes the amount added to proved oil and gas property costs. The future cash outflows associated with settling the asset retirement obligation that have been accrued in the accompanying balance sheets are excluded from the ceiling test calculations. The Company also depletes the estimated dismantlement and abandonment costs, net of salvage values, associated with future development activities that have not yet been capitalized as asset retirement obligations. These costs are also included in the ceiling test calculations. The asset retirement liability is allocated to operating expense using a systematic and rational method.

 

Stock-based Compensation

We record stock-based compensation as a charge to earnings, net of the estimated impact of forfeited awards. As such, we recognize stock-based compensation cost only for those stock-based awards that are estimated to ultimately vest over their requisite service period, based on the vesting provisions of the individual grants. The process of estimating the fair value of stock-based compensation awards and recognizing stock-based compensation cost over their requisite service periods involves significant assumptions and judgments.

 

We estimate the fair value of stock option awards on the date of grant using a Black-Scholes valuation model which requires management to make certain assumptions regarding: (i) the expected volatility in the market price of the Company’s common stock; (ii) dividend yield; (iii) risk-free interest rates; and (iv) the period of time employees are expected to hold the award prior to exercise (referred to as the expected holding period). The expected volatility under this valuation model is based on the current and historical implied volatilities from traded options of our common stock. The dividend yield is based on the approved annual dividend rate in effect and current market price of the underlying common stock at the time of grant. The risk-free interest rate is based on the U.S. Treasury yield curve in effect at the time of grant for bonds with maturities ranging from one month to ten years. The expected holding period of the awards granted is estimated using the historical exercise behavior of employees. In addition, we estimate the expected impact of forfeited awards and recognize stock-based compensation cost only for those awards expected to vest. We use historical experience to estimate projected forfeitures. If actual forfeiture rates are materially different from our estimates, stock-based compensation expense could be significantly different from what we have recorded in the current period. We periodically review actual forfeiture experience and revise our estimates, as considered necessary. The cumulative effect on current and prior periods of a change in the estimated forfeiture rate is recognized as compensation cost in earnings in the period of the revision.

 

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Goodwill and Intangible Assets

We evaluate the recoverability and measure the potential impairment of our goodwill annually. The annual impairment test is a two-step process that begins with the estimation of the fair value of the reporting unit. The first step screens for potential impairment and the second step measures the amount of the impairment, if any. Our estimate of fair value considers the financial projections and future prospects of our business, including its growth opportunities and likely operational improvements. As part of the first step to assess potential impairment, we compare our estimate of fair value for the reporting unit to the book value of the reporting unit. We determine the fair value of the reporting units based on the income approach. Under the income approach, we calculate the fair value of a reporting unit based on the present value of estimated future cash flows. If the book value is greater than our estimate of fair value, we would then proceed to the second step to measure the impairment, if any. The second step compares the implied fair value of goodwill with its carrying value. The implied fair value is determined by allocating the fair value of the reporting unit to all of the assets and liabilities of that unit as if the reporting unit had been acquired in a business combination and the fair value of the reporting unit was the purchase price paid to acquire the reporting unit. The excess of the fair value of the reporting unit over the amounts assigned to its assets and liabilities is the implied fair value of goodwill. If the carrying amount of the reporting unit’s goodwill is greater than its implied fair value, an impairment loss will be recognized in the amount of the excess. We believe our estimation methods are reasonable and reflect common valuation practices.

 

On a quarterly basis, we perform a review of our business to determine if events or changes in circumstances have occurred which could have a material adverse effect on the fair value of the Company and its goodwill. If such events or changes in circumstances were deemed to have occurred, we would perform an impairment test of goodwill as of the end of the quarter, consistent with the annual impairment test performed at the end of our fiscal year on December 31, and record any noted impairment loss.

 

The Company sold its interest in Intercontinental Fuels, LLC on February 7, 2012. As the Company knew of this transaction as of the date of issuance of the Company’s financial statements, we recorded goodwill impairment to the extent of the loss to be recognized on the transaction, or $4,827.

 

Income Taxes

The Company uses the asset and liability approach to account for income taxes. Under this method, deferred tax assets and liabilities are recognized for the expected future tax consequences of differences between the carrying amounts of assets and liabilities and their respective tax bases using tax rates in effect for the year in which the differences are expected to reverse. A valuation allowance is provided when it is more likely than not that some portion or all of the deferred tax assets will not be realized. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period when the change is enacted.

 

On January 1, 2007, the Company adopted an accounting standard which clarifies the accounting for uncertainty in income taxes recognized in financial statements. This standard provides guidance on recognizing, measuring, presenting and disclosing in the financial statements uncertain tax positions that a company has taken or expects to take on a tax return. See Note 20 for further information related to the Company’s accounting for uncertainty in income taxes.

 

Discontinued Operations

The results of operations of a component of an entity that either has been disposed of or is classified as held for sale is reported in discontinued operations if both of the following conditions are met:

 

a. The operations and cash flows of the component have been (or will be) eliminated from the ongoing operations of the entity as a result of the disposal transaction.

b. The entity will not have any significant continuing involvement in the operations of the component after the disposal transaction.

 

In a period in which a component of an entity either has been disposed of or is classified as held for sale, the income statement of the Company for current and prior periods will report the results of operations of the component, including any gain or loss recognized, in discontinued operations. The results of operations of a component classified as held for sale shall be reported in discontinued operations in the period(s) in which they occur.

 

RESULTS OF OPERATIONS

 

The Company sold its wholly-owned subsidiary, IFL, as of February 2012. With knowledge of sale prior to the filing date of this report, the revenues and expenses from that subsidiary have been shown as net income from discontinued operations. The Company’s net income in 2010 has also been separated from the consolidated entity and presented in discontinued operations for comparison purposes.

 

Revenue: The Company’s revenues were $277,917 and $58,107 for the years ended December 31, 2011 and 2010, respectively. The Company’s acquisition of the oil and gas leases during July 2010 (as a result of the Petro Energy acquisition) and the subsequent drilling operations contributed $58,107 in revenue during the last 6 months of 2010.  In 2011, revenues from oil and gas operations increased substantially to $331,024 with additional drilling and workover projects. Royalty expense of $53,107 has been netted from the total amount presented for 2011.

 

13
 

 

Cost of Product Sales:  The Company’s oil and gas segment pays royalty expenses that are recorded as cost of product sales. In 2010, royalty expense was relatively low, at $8,902, primarily due the fact that the company’s oil and gas production only occurred from July through December, 2010. In 2011, cost of product sales totaled $9,407. The Company saw significant increases in its production on the Felix Brandt and James Leonard leases, resulting in royalty expenses of $44,814, which are netted with oil and gas revenues. The balance of the 2011 cost of product sales were attributed to amounts accrued and due BlueRock for their December production payments. See Note 14 for a more detailed discussion of the BlueRock financing arrangement.

 

Payroll and Related Expenses:  With the addition of Adino Exploration on July 1, 2010, the Company hired several employees to operate its leases.  Additionally, the Company has added payroll for one employee at its corporate office. These employee additions result in payroll expense of $218,718 and $90,213 for the years ended December 31, 2011 and 2010, respectively.

 

General and Administrative: The Company’s expenses for the year ended December 31, 2011 and 2010 were $221,803 and $111,350, respectively, an increase of $110,453 or 99%. In July 2010, the Company set up an office in Coleman, Texas to facilitate the development of its oil and gas leases, resulting in additional office expense of $42,845 and $17,193 in insurance expenses for the six months ended December 31, 2010. The same expenses for the full year, 2011 were $44,510 in office expense and $29,996 in insurance expense.

 

With increased production, the Company experienced an increase in severance tax from $3,979 in 2010 to $13,352 in 2011. As production and drilling activity increased, the Company’s travel expenses were escalated from $52,026 in 2010 to $90,678 in 2011.  The Company incurred $30,000 in bad debt expense in September 2010 but had no corresponding expense in 2011.

 

Legal and Professional:  Legal and professional expense was $320,928 and $209,251 for the year ended December 31, 2011 and 2010, respectively. Legal fees increased primarily due to increased expense related to the G J Capital lawsuit. See Item 3 of the Company’s financial statements for additional information regarding the Company’s legal and professional fees.

 

Consulting Expense:  The Company’s consulting expenses were $899,815 and $66,046 for the years ended December 31, 2011 and 2010, respectively, a significant increase. The Company retained the services of a consultant, geologist and petroleum engineer during 2011 to assist in property development, resulting in an increase in 2011 expense over 2010 of $131,350. The Company also retained a marketing consultant in 2011, resulting in non-cash expense of $225,750 for services rendered.

 

Depreciation Expense: Depreciation expense was $95,992 and $51,732 for the years ended December 31, 2011 and 2010, respectively.   The increase is due to the addition of machinery and equipment through the Petro Energy acquisition and $3,407 in asset retirement accretion. The Company has also seen a significant increase in its depletion expense, as production increases. Depletion expense for the years ended December 31, 2011 and 2010 was $52,536 and $20,724, respectively. See Notes 5 and 9 of the Company’s financial statements for additional information regarding these assets and the corresponding depreciation and depletion.

 

Impairment Expense:  Current guidance requires that unamortized capitalized costs (less certain adjustments) for each cost center  not exceed the cost ceiling, which is defined as the present value of future net revenues from estimated production of proved oil and gas reserves (plus certain adjustments). If adjusted unamortized costs capitalized within a cost center exceed the cost center ceiling, the excess is charged to expenses and separately disclosed during the period it occurs. The Company evaluated the carrying cost of the applicable oil producing properties and determined that the asset should be reduced by $47,481 for the year ended December 31, 2010. There was no such impairment required for the year ended December 31, 2011.

 

Operating Supplies: Supplies expense was $34,382 and $24,949 for the years ended December 31, 2011 and 2010, respectively. The increase is due to a full year of exploration and production operations in 2011 versus only six months in 2010.

 

Interest Income:  Interest income was $46,612 and $67,568 for the years ended December 31, 2011 and 2010, respectively. The Company has agreed to an amendment on the $750,000 note receivable with Mr. Sundlun.  This amendment extended the maturity date of the note to August 2011 at no additional interest past the original maturity date of November 6, 2008.  Due to the lack of interest expense, the Company recognized a discount on the note and amortizes that discount through the note’s maturity date. The decrease in income from 2010 to 2011 is a result of the discount being fully amortized at July 31, 2011.

 

Interest Expense:  Interest expense was $304,314 and $170,802 for the years ended December 31, 2011 and 2010, respectively, an increase of $133,512 or 78%. Interest expense increased for 2011 due to the Company entering into several convertible promissory notes payable to Asher, resulting in 8% annual interest to the Company. The Company also entered into a promissory note payable to BlueRock, resulting in 18% annual interest to the Company, and a promissory note payable to the Schwartz Group, resulting in 6% annual interest to the Company. Interest expense consistent between 2010 and 2011 are for the notes to Mr. Sundlun and vehicle financing. See Note 14 of the Company’s financial statements for additional information regarding interest expense.

 

Gain (Loss) on Derivative: The Company entered into a promissory note that permits conversion of the note into shares of the Company’s common stock at a discount to the market price. This discount to market conversion feature is treated as a derivative for accounting purposes. This note also caused two other financial instruments held by the Company to be considered derivatives. The Company has calculated the change in value of those instruments for the year ended December 31, 2011 for a gain of $10,850, compared with a loss of $67,673 for the year ended December 31, 2010. See Note 16 of the Company’s financial statements for a more thorough discussion of this item.

 

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Gain on Change in Fair Value of Clawback: A component of the Petro Energy acquisition agreement gave the former owners of these companies the option to repurchase for $1.00 the assets held by the companies as of July 1, 2010 if the Company’s common stock price fails to reach $0.25 per share within three years of the original acquisition date. This contract clawback provision was valued at $386,739 and $337,354 for the years ended December 31, 2011 and 2010, respectively.

 

Other Expense:  In 2011, the Company had Other Expense of $14,542. Of this total, $4,827 was for goodwill impairment associated with the IFL Sale. The Company also had with no corresponding expense in 2010.

 

Net Income/Loss: The Company had net losses of $1,308,673 and $277,802 for the years ended December 31, 2011 and 2010, respectively. The increased loss was primarily due to increased legal expense and the judgment associated with the GJ Capital lawsuit and increased office, travel, payroll and depreciation expenses for the Company’s oil and gas subsidiary.  Of the totals, net income contributed by IFL was $531,580 and $108,583, for the years ended December 31, 2011 and 2010, respectively. See Note 22 for a detailed statement of operations. The Company also sold its wholly owned subsidiary, Adino Drilling, LLC, to a related party on March 31, 2011, resulting in a loss from discontinued operations of $252,524, as the note receivable of $500,000 was disallowed for reporting purposes.  See Note 21 for a more thorough discussion of the sale.

 

Cash:  The Company’s available cash increased at December 31, 2011 to $381,945 up from $285,172 at December 31, 2010. In December 2011, the Company received additional investment from members of the Schwartz group of $150,000. The Company also had deposits from the BlueRock financing for well completion. Of the cash on hand, $70,800 was reserved for tax payments by IFL and $50,000 was on deposit for a Texas oil and gas operator license held by Adino Exploration.

 

LIQUIDITY AND CAPITAL RESOURCES

 

The Company’s access to financing improved somewhat during 2010 and 2011, due to several convertible notes that we issued to two groups of private investors. As a result of these private note issuances, the Company raised $1,212,380. The Company is not required to repay most of this financing until the third quarter of 2013, thereby providing the Company a longer period to earn the money necessary to pay off the notes.

 

The Company’s available cash increased at December 31, 2011 to $381,945 up from $282,272 at December 31, 2010. In December 2011, the Company received additional investment from members of the Schwartz group of $150,000. The Company also had deposits from the BlueRock financing for well completion. Of the cash on hand, $70,800 was reserved for tax payments by IFL and $50,000 was on deposit for a Texas oil and gas operator license held by Adino Exploration

 

As of December 31, 2011, the Company has a working capital deficit of $4,693,961 and total stockholders’ deficit of $2,716,051.  These factors raise substantial doubt regarding the Company’s ability to continue as a going concern. The ability of the Company to continue as a going concern depends upon its ability to obtain funding for its working capital deficit. Of the outstanding current liabilities at December 31, 2011, there are several non-cash items: , $386,739 is due to a non-cash clawback provision and $136,894 is attributed to a derivative liability.  Additionally, $1,013,034 of the outstanding current liability is due to certain officers and directors for prior years’ accrued compensation.  They have agreed in writing to postpone payment if necessary, should the Company need capital it would otherwise pay these individuals.  The Company plans to satisfy current year and future cash flow requirements through its existing, growing business operations. The Company also hopes to pursue merger and acquisition opportunities including the expansion of existing business opportunities, primarily in the oil and gas exploration and production sector.

 

ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

Item 7A is not required for a smaller reporting company.

 

15
 

 

 

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

To the Board of Directors

Adino Energy Corporation

Houston, Texas

 

We have audited the accompanying consolidated balance sheets of Adino Energy Corporation (the “Company”) as of December 31, 2011 and 2010 and the related statements of operations, stockholders' 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 audit.

 

We conducted our audit in accordance with 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 audit provides a reasonable basis for our opinion.

 

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Adino Energy Corporation as of December 31, 2011 and 2010 and the results of its operations and cash flows for the period described above 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.  The Company has suffered recurring losses from operations and maintains a working capital deficit. These matters raise substantial doubt about the Company’s ability to continue as a going concern.  These financial statements do not include any adjustments relating to the recoverability and classification of asset carrying amounts or the amount and classification of liabilities that may result should the Company be unable to continue as a going concern. See note 2 to the financial statements for further information regarding this uncertainty.

 

/s/ M&K CPAS, PLLC

 

www.mkacpas.com

Houston, Texas

April 16, 2012

 

16
 

 

ADINO ENERGY CORPORATION

Consolidated Balance Sheets

AS OF DECEMBER 31, 2011 AND 2010

   December 31, 2011   December 31, 2010 
ASSETS          
Cash in bank  $331,945   $282,272 
Certificate of deposit - restricted   50,000    - 
Accounts receivable   14,859    9,615 
Deposits and prepaid assets   66,908    64,562 
Notes receivable, net of unamortized discount of $0 and $46,570 at December 31, 2011 and 2010, respectively   750,000    703,430 
Interest receivable   375,208    375,208 
Other assets   25,001    - 
Total current assets   1,613,921    1,435,087 
           
Fixed assets, net of accumulated depreciation of $109,715 and $69,052, respectively   520,342    165,648 
Oil and gas properties (full cost method), net of accumulated amortization, depreciation, depletion, and asset impairment          
Proved properties   406,025    155,279 
Unproved properties   280,602    59,060 
Goodwill   1,554,413    1,566,379 
Discontinued operations - net assets held for sale   -    357,314 
Total non-current assets   2,761,382    2,303,680 
TOTAL ASSETS  $4,375,303   $3,738,767 
           
LIABILITIES AND SHAREHOLDERS’ DEFICIT          
Accounts payable  $650,235   $413,515 
Accounts payable - related party   82,387    47,200 
Accrued liabilities   270,654    334,912 
Accrued liabilities - related party   1,013,034    909,960 
Asset retirement obligation   50,944    36,689 
Contract clawback provision   386,739    337,354 
Notes payable - current portion   2,445,363    1,864,251 
Interest payable   830,360    660,000 
Derivative liability   136,894    103,511 
Deferred revenue   50,000    - 
Deferred gain - current portion   391,272    391,272 
Discontinued operations – liabilities held for sale   -    44,884 
Total current liabilities   6,307,882    5,143,548 
           
Deferred gain, net of current portion   293,465    684,744 
Notes payable, net of current portion   490,007    413,845 
TOTAL LIABILITIES   7,091,354    6,242,137 
           
SHAREHOLDERS’ DEFICIT          
Preferred stock, $0.001 par value, 20,685,250 shares authorized, 109,642 shares outstanding   685,558    - 
Capital stock, $0.001 par value, 500 million shares authorized, 125,574,295 and 107,260,579 shares issued and outstanding at December 31, 2011 and December 31, 2010, respectively   125,573    107,260 
Additional paid in capital   14,177,563    13,785,442 
Retained deficit   (17,704,745)   (16,396,072)
Total shareholders’ deficit   (2,716,051)   (2,503,370)
TOTAL LIABILITIES AND SHAREHOLDERS’ DEFICIT  $4,375,303   $3,738,767 

 

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

 

17
 

 

ADINO ENERGY CORPORATION

Consolidated Statements of Operations

FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010

 

   December 31,   December 31, 
   2011   2010 
         
REVENUES          
Oil and gas operations   277,917    58,107 
Total revenues   277,917    58,107 
           
OPERATING EXPENSES          
Cost of product sales   9,407    12,214 
Payroll and related expenses   218,718    90,213 
General and administrative   221,803    111,350 
Legal and professional   320,928    209,251 
Consulting fees   899,815    66,046 
Repairs   22,807    20,258 
Depreciation, depletion and accretion   95,992    51,732 
Impairment expense   -    47,481 
Operating supplies   34,382    24,949 
Total operating expenses   1,823,852    633,494 
           
OPERATING LOSS   (1,545,935)   (575,387)
           
OTHER INCOME AND EXPENSES          
Interest income   46,612    67,568 
Interest expense   (304,314)   (170,802)
Gain (loss) on derivative   10,850    (67,673)
Gain (loss) on change in fair value of clawback provision   (49,385)   71,406 
Other expense   (14,542)   - 
Total other income and expense   (310,779)   (99,501)
           
LOSS FROM CONTINUING OPERATIONS  $(1,856,714)  $(674,888)
           
DISCONTINUED OPERATIONS          
Income from operations of discontinued Intercontinental Fuels, LLC   820,083    397,086 
Loss from operations of discontinued Adino Drilling, LLC   (272,042)   - 
           
NET LOSS  $(1,308,673)  $(277,802)
           
Net income (loss) per share, basic and fully diluted – continuing operations  $(0.02)  $(0.01)
Net income (loss) per share, basic and fully diluted – discontinued operations  $0.00   $0.00 
Total net income (loss) per share, basic and fully diluted  $(0.01)  $(0.00)
           
Weighted average shares outstanding, basic and fully diluted   114,945,584    99,512,634 

 

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

 

18
 

 

ADINO ENERGY CORPORATION

Consolidated Statement of Changes in Shareholders’ Deficit

FOR THE YEARS ENDED DECEMBER 31, 2010 and 2011

 

   Common
Stock
Shares
   Common
Stock
Amount
   Preferred
Shares
   Preferred
Stock
Amount
   APIC   Retained
Earnings
(Deficit)
   Total 
                             
Balance December 31, 2009   93,260,579   $93,260    -   $-   $13,527,242   $(16,118,270)  $(2,497,768)
                                    
Shares issued for services - officers   1,500,000    1,500    -    -    50,200    -    51,700 
Shares issued for acquisition   2,500,000    2,500    -    -    68,000    -    70,500 
Shares issued for services   10,000,000    10,000    -    -    140,000    -    150,000 
Net loss   -    -    -    -    -    (277,802)   (277,802)
Balance December 30, 2010   107,260,579   $107,260    -   $-   $13,785,442   $(16,396,072)  $(2,503,370)
                                    
Shares issued in debt conversion - common   6,563,716    6,563    -    -    98,936    -    105,499 
Derivative settlement   -    -    -    -    62,826    -    62,826 
Shares issued for services   11,750,000    11,750    -    -    230,359    -    242,109 
Shares issued in debt conversion - preferred   -    -    5,358    187,500    -    -    187,500 
Shares issued for cash   -    -    4,284    150,000    -    -    150,000 
Shares issued in asset purchase   -    -    100,000    350,000              350,000 
Dividend on preferred stock   -    -    -    (1,942)   -    -    (1,942)
Net loss   -    -    -    -    -    (1,308,673)   (1,308,673)
Balance December 31, 2011   125,574,295   $125,573    109,642   $685,558   $14,177,563   $(17,704,745)  $(2,716,051)

 

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

 

19
 

 

ADINO ENERGY CORPORATION

Consolidated Statements of Cash Flows

FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010

 

   December 31,   December 31, 
   2011   2010 
         
CASH FLOWS FROM OPERATING ACTIVITIES:          
Net loss  $(1,308,673)  $(277,802)
           
Adjustments to reconcile net (loss) to net cash (used in) operating activities:          
Depreciation and depletion   128,037    61,410 
Accretion   3,704    868 
Amortization of discount on note receivable   (46,570)   (67,568)
Loss on sale of subsidiary   252,524    - 
Shares issued for services   242,109    122,200 
Bad debt expense   -    30,000 
Goodwill impairment – IFL   4,827    - 
Gain from lawsuit / sale amortization   (391,279)   (391,278)
Gain on debt forgiveness   -    (65,000)
(Gain) / loss on change in fair value of derivative   (10,847)   67,673 
Gain on change in fair value of clawback provision   49,385    (71,406)
Oil and gas impairment   -    47,481 
Amortization of debt discount   82,878    9,031 
Changes in operating assets and liabilities:          
Accounts receivable   4,756    57,116 
Inventory   (25,001)   - 
Other assets   (12,346)   (14,306)
Accounts payable and accrued liabilities   539,572    56,599 
Deferred revenue   50,000    - 
Net cash (used in) operating activities   (436,924)   (434,982)
           
CASH FLOWS FROM INVESTING ACTIVITIES:          
Purchase of equipment   (590,755)   (223,190)
Net cash (used in) investing activities   (590,755)   (223,190)
           
CASH FLOWS FROM FINANCING ACTIVITIES:          
Proceeds from preferred stock investment   150,000    - 
Borrowings on note payable   1,062,380    457,500 
Principal payments on note payable   (87,928)   (16,698)
Net cash provided by financing activities   1,124,452    440,802 
           
Net change in cash and cash equivalents   96,773    (217,370)
Cash and cash equivalents, beginning of period   285,172    502,542 
Cash and cash equivalents, end of period  $381,945   $285,172 
           
Cash paid for:          
Interest  $12,582   $12,285 
Income taxes  $-   $- 
Supplemental disclosures of non-cash information:          
Contract clawback provision  $-   $408,760 
Acquisition purchased with preferred stock  $350,000   $150,000 
Asset retirement obligation  $10,551   $36,255 
Note discount  $-   $35,838 
Operating license deposit  $-   $50,000 
Reduction in derivative due to debt conversion  $62,826   $- 
Conversion of note – preferred stock  $293,000   $- 
Derivative liability new debt  $107,059   $- 
Accrual of dividend payable  $1,942   $- 

 

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

 

20
 

 

ADINO ENERGY CORPORATION

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

NOTE 1 - ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 

Background

 

Adino was incorporated under the laws of the State of Montana on August 13, 1981, under the name Golden Maple Mining and Leaching Company, Inc. In 1985, the Company ceased its mining operations and discontinued all business operations in 1990. The Company then acquired Consolidated Medical Management, Inc. (“CMMI”) and kept the CMMI name. The Company initially focused its efforts on the continuation of the business services offered by CMMI. These services focused on the delivery of turn-key management services for the home health industry, predominately in south Louisiana. The Company exited the medical business in December 2000. In August 2001, the Company decided to refocus on the oil and gas industry. In 2006, we decided to cease our oil and gas activities and focus on becoming a fuel company.

 

The Company’s wholly owned subsidiary, Intercontinental Fuels, LLC (“IFL”), a Texas limited liability company, was founded in 2003. Adino first acquired 75% of IFL’s membership interests in 2003. The Company acquired 100% ownership of IFL shortly thereafter.

 

In January 2008, the Company changed its name to Adino Energy Corporation. We believe that this name better reflects our current and future business activities, as we plan to continue focusing on the energy industry.

 

As of July 1, 2010, the Company acquired PetroGreen Energy LLC, a Nevada limited liability company, and AACM3, LLC, a Texas limited liability company d/b/a Petro 2000 Exploration Co. (together "Petro Energy"). Petro Energy is a licensed Texas oilfield operator currently operating 11 wells on two leases covering approximately 300 acres in Coleman County, Texas. Petro Energy also owns a drilling rig, two service rigs and associated tools and equipment. The Company also acquired the operator license held by the principal of Petro Energy.

 

After the acquisition of Petro Energy, the Company created two wholly owned subsidiaries:  Adino Exploration, LLC (“Adino Exploration”) and Adino Drilling, LLC (“Adino Drilling”).  All oil and gas leases were transferred from the Petro Energy companies to Adino Exploration and future oil and gas exploration acquisitions and activity are to be operated through this company.  The large drilling rig acquired in the Petro Energy transaction and other associated drilling machinery and equipment were transferred to Adino Drilling.

 

On March 31, 2011, the Company sold the membership interest of Adino Drilling, LLC to a related party.  Under the terms of the agreement, the Company realized a reduction in accrued liability of $100,000 and acquired a $500,000 six year, 5.24% interest note receivable, for a total sale price of $600,000.  The sale resulted in a gain to the Company of $247,376; however the transaction’s related party note of $500,000 is not allowed for reporting purposes, therefore the Company has a reportable loss of $252,624.

 

On or about October 12, 2011 Adino signed a letter of intent to purchase all of the assets of Ashton, AOS 1A, and AOS 1-B. The proposed purchase price for the assets was $6,000,000 in face value of convertible preferred stock of the Company, with the preferred stock converting to common stock at the rate of $0.15 per share. The parties agreed that partial closing of the purchase would occur once the sellers received clear title to the assets subject to the agreement. The first partial closing of purchase occurred on November 3, 2011, and the Company issued 100,000 shares of Adino's Class "B" Preferred Stock Series 1 (the "Preferred Stock"), as follows: 95,534 shares to AOS 1A, and 4,466 shares to AOS 1-B. The Preferred Stock shall be convertible into common shares at AOS 1A or AOS 1-B's option at any time after six months, provided that (a) immediately after the first six months, only 25% of the Preferred Stock may be converted to common stock, and (b) each month thereafter, only up to 12.5% of the Preferred Stock may be converted to common stock. The Preferred Stock shall have other terms as determined by Adino's Board of Directors. The number of shares of Preferred Stock was chosen to conform to the agreed upon value of $1,500,000 for the assets. The Company later decided not to acquire the remaining Ashton assets. On February 7, 2012 (subsequent to the period covered by this report), the Company sold all oilfield machinery and equipment it had purchased from Ashton Oilfield Services in its November 2011 acquisition for $500,000 cash.

 

With the Company’s focus on oil and gas exploration and production, the Company decided to sell its interest in IFL. To that end, on February 7, 2012 (subsequent to the period covered by this report), Adino sold all of its membership interest in IFL to Pomisu XXI S.L., for $900,000.

 

Use of Estimates

 

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect reported amounts and related disclosures.  Actual results could differ from those estimates.

 

21
 

 

Principles of Consolidation

The consolidated financial statements include all of the assets, liabilities and results of operations of subsidiaries in which the Company has a controlling interest. All significant inter-company accounts and transactions among consolidated entities have been eliminated.

 

Concentrations of Credit Risk

Financial instruments which subject the Company to concentrations of credit risk include cash and cash equivalents and accounts receivable.

 

The Company maintains its cash in well-known banks selected based upon management’s assessment of the banks’ financial stability. Balances rarely exceed the $250,000 federal depository insurance limit. The Company has not experienced any losses on deposits and believes the risk of loss is minimal.

 

For the years ended December 31, 2011 and 2010, we had no reserve for doubtful accounts as all of our receivables were collected early in the subsequent period and had no expectation of loss. Management assesses the need for an allowance for doubtful accounts based upon the financial strength of our customers, historical experience with our customers and the aging of the amounts due.

 

Cash Equivalents

For purposes of reporting cash flows, the Company considers all short-term investments with an original maturity of three months or less to be cash equivalents.  We had no cash equivalents at either December 31, 2011 or December 31, 2010.

 

Investments

The Company from time to time maintains a portfolio of marketable investment securities for deposit requirements associated with our oil and gas operator licenses. The securities have an investment grade and a term to earliest maturity generally of ten months to over one year and include certificates of deposit. These securities are carried at cost, which approximates market. The Company’s securities are classified as held-to-maturity because the Company has the positive intent and ability to hold the securities to maturity.

 

Other Assets

Supplies consisting of equipment and parts to be used for future drilling projects and repair to existing wells, are stated at cost.  As the supplies are assigned to a particular project, they are then capitalized or expensed, accordingly.  Supplies are evaluated at each balance sheet date for obsolescence and impairment.

 

Property and Equipment

Property and equipment are recorded at cost.  Depreciation is provided on the straight-line method over the estimated useful lives of the assets, which range from three to fifteen years.  Expenditures for major renewals and betterments that extend the original estimated economic useful lives of the applicable assets are capitalized.  Expenditures for normal repairs and maintenance are charged to expense as incurred.  The cost and related accumulated depreciation of assets sold or otherwise disposed of are removed from the accounts, and any gain or loss is included in operations.

 

Oil and Gas Producing Activities

The Company follows the full cost method of accounting for oil and gas operations whereby all costs associated with the exploration and development of oil and gas properties are initially capitalized into a single cost center (“full cost pool”). Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties and costs of drilling directly related to acquisition and exploration activities. Proceeds from property sales are generally credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 25% or more of the proved reserves related to a full cost pool.

 

Depletion of exploration and production costs and depreciation of production equipment is computed using the units of production method based upon estimated proved oil and gas reserves as determined by consulting engineers and prepared (annually) by independent petroleum engineers. Costs included in the depletion base to be amortized include (a) all proved capitalized costs including capitalized asset retirement costs, net of estimated salvage values, less accumulated depletion, (b) estimated future development cost to be incurred in developing proved reserves; and (c) estimated dismantlement and abandonment costs, net of estimated salvage values that have not been included as capitalized costs because they have not yet been capitalized in asset retirement costs. The costs of unproved properties are withheld from the depletion base until it is determined whether or not proved reserves can be assigned to the properties. The unproved properties are reviewed quarterly for impairment. When proved reserves are assigned or the unproved property is considered to be impaired, the cost of the property or the amount of the impairment is added to the costs subject to depletion calculations.

 

Current guidance requires that  unamortized capitalized costs (less certain adjustments) for each cost center  not exceed the cost ceiling, which is defined as the present value of future net revenues from estimated production of proved oil and gas reserves (plus certain adjustments). If adjusted unamortized costs capitalized within a cost center exceed the cost center ceiling, the excess is charged to expenses and separately disclosed during the period it occurs. The Company evaluates the carrying cost of the applicable oil producing properties for any impairment as required.

 

22
 

 

Derivatives

The Company does not use derivative instruments to hedge exposures to cash flow, market, or foreign currency risks. Derivative financial instruments are initially measured at their fair value. For derivative financial instruments that are accounted for as liabilities, the derivative instrument is initially recorded at its fair value and is then revalued at each reporting date, with changes in the fair value reported as charges or credits to income. For option−based derivative financial instruments, the Company uses the lattice model to value the derivative instruments. The classification of derivative instruments, including whether such instruments should be recorded as liabilities or as equity, is reassessed at the end of each reporting period. Derivative instrument liabilities are classified in the balance sheet as current or non−current based on whether or not cash settlement of the derivative instrument could be required within 12 months of the balance sheet date.

 

Asset Retirement Obligation

The Company accounts for its asset retirement obligations by recording the fair value of a liability for an asset retirement obligation recognized for the period in which it was incurred if a reasonable estimate of fair value could be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The increase in carrying value of a property associated with the capitalization of an asset retirement cost is included in proved oil and gas properties in the consolidated balance sheets. The Company depletes the amount added to proved oil and gas property costs. The future cash outflows associated with settling the asset retirement obligation that have been accrued in the accompanying balance sheets are excluded from the ceiling test calculations. The Company also depletes the estimated dismantlement and abandonment costs, net of salvage values, associated with future development activities that have not yet been capitalized as asset retirement obligations. These costs are also included in the ceiling test calculations. Accretion of the asset retirement liability is allocated to operating expense using the discount method.

 

Revenue Recognition

IFL earns revenue from throughput and storage fees on a monthly basis. The Company recognizes revenue from throughput fees in the month that the services are provided based upon contractually determined rates. The Company recognizes storage fee revenue in the month that the service is provided in accordance with our customer contracts.

 

As described above, in accordance with the requirement of current guidance, the Company recognizes revenue when (1) persuasive evidence of an arrangement exists (contracts) (2) delivery has occurred (monthly) (3) the seller’s price is fixed or determinable (per the customer’s contract or current market price) and (4) collectability is reasonably assured (based upon our credit policy).

 

The Company has performed an analysis and determined that gross revenue reporting is appropriate, since (1) the Company is the primary obligor in the transaction (2) the Company has latitude in establishing price and (3) the Company provides the product and performs part of the service.

 

Adino Exploration earns revenue from the sale of oil.  The Company recognizes oil, gas and natural gas condensate revenue in the period of delivery.  Settlement for oil sales occurs 30 days after the oil has been sold; and settlement for gas sales would occur 60 days after the gas had been sold.  The Company recognizes revenue when an arrangement exists, the product or service has been provided, the sales price is fixed or determinable, and collectability is reasonably assured.

 

Income Taxes

The Company uses the asset and liability approach to account for income taxes. Under this method, deferred tax assets and liabilities are recognized for the expected future tax consequences of differences between the carrying amounts of assets and liabilities and their respective tax bases using tax rates in effect for the year in which the differences are expected to reverse. A valuation allowance is provided when it is more likely than not that some portion or all of the deferred tax assets will not be realized. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period when the change is enacted.

 

On January 1, 2007, the Company adopted an accounting standard which clarifies the accounting for uncertainty in income taxes recognized in financial statements. This standard provides guidance on recognizing, measuring, presenting and disclosing in the financial statements uncertain tax positions that a company has taken or expects to take on a tax return.

 

Income (Loss) Per Share

Current guidance requires earnings per share (“EPS”) to be computed and reported as both basic EPS and diluted EPS. Basic EPS is computed by dividing net income by the weighted average number of common shares outstanding for the period. Diluted EPS is computed by dividing net income by the weighted average number of common shares and dilutive common stock equivalents (convertible notes and interest on the notes, stock awards and stock options) outstanding during the period. Dilutive EPS reflects the potential dilution that could occur if options to purchase common stock were exercised for shares of common stock.   The dilutive effect of convertible instruments on earnings per share is not presented in the consolidated statements of operations for periods with a net loss.

 

23
 

 

 Stock-Based Compensation

We record stock-based compensation as a charge to earnings, net of the estimated impact of forfeited awards. As such, we recognize stock-based compensation cost only for those stock-based awards that are estimated to ultimately vest over their requisite service period, based on the vesting provisions of the individual grants. The process of estimating the fair value of stock-based compensation awards and recognizing stock-based compensation cost over their requisite service periods involves significant assumptions and judgments.

 

We estimate the fair value of stock option awards on the date of grant using a Black-Scholes valuation model which requires management to make certain assumptions regarding: (i) the expected volatility in the market price of the Company’s common stock; (ii) dividend yield; (iii) risk-free interest rates; and (iv) the period of time employees are expected to hold the award prior to exercise (referred to as the expected holding period). The dividend yield is based on the approved annual dividend rate in effect and current market price of the underlying common stock at the time of grant. The risk-free interest rate is based on the U.S. Treasury yield curve in effect at the time of grant for bonds with maturities ranging from one month to ten years. The expected holding period of the awards granted is estimated using the historical exercise behavior of employees. In addition, we estimate the expected impact of forfeited awards and recognize stock-based compensation cost only for those awards expected to vest. We use historical experience to estimate projected forfeitures. If actual forfeiture rates are materially different from our estimates, stock-based compensation expense could be significantly different from what we have recorded in the current period. We periodically review actual forfeiture experience and revise our estimates, as considered necessary. The cumulative effect on current and prior periods of a change in the estimated forfeiture rate is recognized as compensation cost in earnings in the period of the revision.

 

The Company has granted options and warrants to purchase Adino’s common stock.  These instruments have been valued using the Black-Scholes model.

 

Impairment of Long-Lived Assets

In the event that facts and circumstances indicate that the carrying value of a long-lived asset may be impaired, an evaluation of recoverability is performed by comparing the estimated future undiscounted cash flows associated with the asset or the asset’s estimated fair value to the asset’s carrying amount to determine if a write-down to market value or discounted cash flow is required.

 

For the years ended December 31, 2011 and 2010, Adino evaluated and determined that no impairment was warranted on the fixed assets of the Company.  Additionally, no impairment was required on the oil and gas assets of the Company.  There was no change to the impairment analysis performed at the December 31, 2010 audit and no indicators of impairment at the review.  See Notes 5 and 9 for a more thorough discussion of the Company’s fixed assets and oil and gas assets as of December 31, 2011.

 

Goodwill

Goodwill is our single largest asset. We evaluate the recoverability and measure the potential impairment of our goodwill annually. The annual impairment test is a two-step process that begins with the estimation of the fair value of the reporting unit. The first step screens for potential impairment and the second step measures the amount of the impairment, if any. Our estimate of fair value considers the financial projections and future prospects of our business, including its growth opportunities and likely operational improvements. As part of the first step to assess potential impairment, we compare our estimate of fair value for the reporting unit to the book value of the reporting unit. We determine the fair value of the reporting units based on the income approach. Under the income approach, we calculate the fair value of a reporting unit based on the present value of estimated future cash flows. If the book value is greater than our estimate of fair value, we would then proceed to the second step to measure the impairment, if any. The second step compares the implied fair value of goodwill with its carrying value. The implied fair value is determined by allocating the fair value of the reporting unit to all of the assets and liabilities of that unit as if the reporting unit had been acquired in a business combination and the fair value of the reporting unit was the purchase price paid to acquire the reporting unit. The excess of the fair value of the reporting unit over the amounts assigned to its assets and liabilities is the implied fair value of goodwill. If the carrying amount of the reporting unit’s goodwill is greater than its implied fair value, an impairment loss will be recognized in the amount of the excess. We believe our estimation methods are reasonable and reflect common valuation practices.

 

In December 2010, the FASB issued FASB ASU No. 2010-28, “When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts,” which is now codified under FASB ASC Topic 350, “Intangibles — Goodwill and Other.” This ASU provides amendments to Step 1 of the goodwill impairment test for reporting units with zero or negative carrying amounts. For those reporting units, an entity is required to perform Step 2 of the goodwill impairment test if it is more likely than not goodwill impairment exists. When determining whether it is more likely than not impairment exists, an entity should consider whether there are any adverse qualitative factors, such as a significant deterioration in market conditions, indicating impairment may exist. FASB ASU No. 2010-28 is effective for fiscal years (and interim periods within those years) beginning after December 15, 2010. Upon adoption of the amendments, an entity with reporting units having carrying amounts which are zero or negative is required to assess whether it is more likely than not the reporting units’ goodwill is impaired. If the entity determines impairment exists, the entity must perform Step 2 of the goodwill impairment test for that reporting unit or units. Step 2 involves allocating the fair value of the reporting unit to each asset and liability, with the excess being implied goodwill. An impairment loss results if the amount of recorded goodwill exceeds the implied goodwill. Any resulting goodwill impairment should be recorded as a cumulative-effect adjustment to beginning retained earnings in the period of adoption.

 

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 On a quarterly basis, we perform a review of our business to determine if events or changes in circumstances have occurred which could have a material adverse effect on the fair value of the Company and its goodwill. If such events or changes in circumstances were deemed to have occurred, we would perform an impairment test of goodwill as of the end of the quarter, consistent with the annual impairment test performed at the end of our fiscal year on December 31, and record any noted impairment loss.

 

With our knowledge of the loss realized on the IFL sale in February 2012, the Company has recorded an impairment of $4,827 at December 31, 2011, the amount of the loss recognized on the transaction. No such knowledge or expectation of loss was present at December 31, 2010 or the quarters ended March 31, June 30 and September 30, 2011.

 

Fair Value of Financial Instruments

On January 1, 2008, the Company adopted a new standard related to the accounting for financial assets and financial liabilities and items that are recognized or disclosed at fair value in the financial statements on a recurring basis, at least annually. This standard provides a single definition of fair value and a common framework for measuring fair value as well as new disclosure requirements for fair value measurements used in financial statements. Fair value measurements are based upon the exit price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants exclusive of any transaction costs, and are determined by either the principal market or the most advantageous market. The principal market is the market with the greatest level of activity and volume for the asset or liability. Absent a principal market to measure fair value, the Company would use the most advantageous market, which is the market that the Company would receive the highest selling price for the asset or pay the lowest price to settle the liability, after considering transaction costs. However, when using the most advantageous market, transaction costs are only considered to determine which market is the most advantageous and these costs are then excluded when applying a fair value measurement. The adoption of this standard did not have a material effect on the Company’s financial position, results of operations or cash flows.

 

On January 1, 2009, the Company adopted an accounting standard for applying fair value measurements to certain assets, liabilities and transactions that are periodically measured at fair value. The adoption did not have a material effect on the Company’s financial position, results of operations or cash flows.

 

In August 2009, the FASB issued an amendment to the accounting standards related to the measurement of liabilities that are routinely recognized or disclosed at fair value. This standard clarifies how a company should measure the fair value of liabilities, and that restrictions preventing the transfer of a liability should not be considered as a factor in the measurement of liabilities within the scope of this standard. This standard became effective for the Company on October 1, 2009. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements.

 

The fair value accounting standard creates a three-level hierarchy to prioritize the inputs used in the valuation techniques to derive fair values. The basis for fair value measurements for each level within the hierarchy is described below with Level 1 having the highest priority and Level 3 having the lowest.

 

Level 1: Quoted prices in active markets for identical assets or liabilities.

 

Level 2:Quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar instruments in markets that are not active; and model-derived valuations in which all significant inputs are observable in active markets.

 

Level 3:Valuations derived from valuation techniques in which one or more significant inputs are unobservable.

 

Discontinued Operations

 

The results of operations of a component of an entity that either has been disposed of or is classified as held for sale is reported in discontinued operations if both of the following conditions are met:

 

a. The operations and cash flows of the component have been (or will be) eliminated from the ongoing operations of the entity as a result of the disposal transaction.

 

b. The entity will not have any significant continuing involvement in the operations of the component after the disposal transaction.

In a period in which a component of an entity either has been disposed of or is classified as held for sale, the income statement of the Company for current and prior periods will report the results of operations of the component, including any gain or loss recognized, in discontinued operations. The results of operations of a component classified as held for sale shall be reported in discontinued operations in the period(s) in which they occur.

 

Reclassification

Certain amounts reported in the prior period financial statements may have been reclassified to the current period presentation.

 

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Recently Issued Accounting Pronouncements

 

In January 2010, the FASB issued an amendment to the accounting standards related to the disclosures about an entity’s use of fair value measurements. Among these amendments, entities will be required to provide enhanced disclosures about transfers into and out of the Level 1 (fair value determined based on quoted prices in active markets for identical assets and liabilities) and Level 2 (fair value determined based on significant other observable inputs) classifications, provide separate disclosures about purchases, sales, issuances and settlements relating to the tabular reconciliation of beginning and ending balances of the Level 3 (fair value determined based on significant unobservable inputs) classification and provide greater disaggregation for each class of assets and liabilities that use fair value measurements. Except for the detailed Level 3 roll-forward disclosures, the new standard is effective for the Company for interim and annual reporting periods beginning after December 31, 2009. The requirement to provide detailed disclosures about the purchases, sales, issuances and settlements in the roll-forward activity for Level 3 fair value measurements is effective for the Company for interim and annual reporting periods beginning after December 31, 2011. The Company does not expect that the adoption of this new standard will have a material impact to its consolidated financial statements.

 

In January 2010, the FASB issued an ASU to amend existing oil and gas reserve accounting and disclosure guidance to align its requirements with the SECs revised rules.  The significant revisions involve revised definitions of oil and gas producing activities, changing the pricing used to estimate reserves at period end to a twelve month arithmetic average of the first day of the month prices and additional disclosure requirements.  In contrast to the SEC rule, the FASB does not permit the disclosure of probable and possible reserves in the supplemental oil and gas information in the notes to the financial statements. The amendments are effective for annual reporting periods ending on or after December 31, 2009.  Application of the revised rules is prospective and companies are not required to change prior period presentation to conform to the amendments.

 

In September 2011, the FASB has issued ASU No. 2011-08, Intangibles—Goodwill and Other (Topic 350): Testing Goodwill for Impairment. ASU 2011-08 is intended to simplify how entities, both public and nonpublic, test goodwill for impairment. ASU 2011-08 permits an entity to first assess qualitative factors to determine whether it is “more likely than not” that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test described in Topic 350, Intangibles-Goodwill and Other. The more-likely-than-not threshold is defined as having a likelihood of more than 50%. ASU 2011-08 is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. The Company does not expect the adoption of ASU 2011-08 to have any impact on its consolidated financial statements.

 

In December 2011, the FASB issued Accounting Standards Update No. 2011-11, “Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities,” (“ASU 2011-11”). ASU 2011-11 enhances disclosures regarding financial instruments and derivative instruments. Entities are required to provide both net information and gross information for these assets and liabilities in order to enhance comparability between those entities that prepare their financial statements on the basis of U.S. GAAP and those entities that prepare their financial statements on the basis of IFRS. This new guidance is to be applied retrospectively. The adoption of these provisions does not have a material impact on the Company’s consolidated financial statements.

 

NOTE 2 - GOING CONCERN

 

As of December 31, 2011, the Company has a working capital deficit of $4,693,961 and total stockholders’ deficit of $2,716,051.  These factors raise substantial doubt regarding the Company’s ability to continue as a going concern. The ability of the Company to continue as a going concern depends upon its ability to obtain funding for its working capital deficit. Of the outstanding current liabilities at December 31, 2011, there are several non-cash items: $386,739 is due to a non-cash clawback provision and $136,894 is attributed to a derivative liability.  Additionally, $1,013,034 of the outstanding current liability is due to certain officers and directors for prior years’ accrued compensation.  They have agreed in writing to postpone payment if necessary, should the Company need capital it would otherwise pay these individuals.  The Company plans to satisfy current year and future cash flow requirements through its existing, growing business operations. The Company also hopes to pursue merger and acquisition opportunities including the expansion of existing business opportunities, primarily in the oil and gas exploration and production sector.

 

NOTE 3 - LEASE COMMITMENTS

 

On April 1, 2007, IFL agreed to lease the IFL fuel terminal from 17617 Aldine Westfield Road, LLC for 18 months at $15,000 per month. The lease included an option to purchase the terminal for $3.55 million by September 30, 2008. The Company evaluated this lease and determined that it qualified as a capital lease for accounting purposes.  The terminal was capitalized at $3,179,572, calculated using the present value of monthly rent at $15,000 for the months April 2007 – September 2008 and the final purchase price of $3.55 million discounted at IFL’s incremental borrowing rate of 12.75%.  The terminal was depreciated over its useful life of 15 years resulting in monthly depreciation expense of $17,664.  As of December 31, 2007, the carrying value of the capital lease liability was $3,355,984.

 

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Due to the difficult credit markets, the Company was unable to secure financing for the Houston terminal facility and assigned its rights under the terminal purchase option to Lone Star Fuel Storage and Transfer, LLC (“Lone Star”).  Lone Star purchased the terminal from 17617 Aldine Westfield Road, LLC on September 30, 2008.  Lone Star then entered into a five year operating lease with option to purchase with IFL.  The five year lease has monthly rental payments of $30,000, escalating 3% per year.  IFL’s purchase option allows for the terminal to be purchased at any time prior to October 1, 2009 for $7,775,552.  The sale price escalates $1,000,000 per year after this date, through the lease expiration date of September 30, 2013.  The Company recognizes the escalating lease payments on a straight line basis.  As of December 31, 2011, the Company has not exercised its option to purchase the Houston terminal facility.

 

The Lone Star lease was evaluated and was deemed to be an operating lease.

 

The transactions that led to the above two leases both resulted in gains to the Company.  The lawsuit settlement just prior to the lease with 17617 Aldine Westfield Road, LLC resulted in a gain to the Company of $1,480,383.  The Company initially amortized this gain over the life of the capital lease (18 months), but later recognized that this time frame was in error.  The appropriate amortization period for the gain is the life of the capital asset, or 15 years.   The Company has restated all appropriate periods to reflect this change and reported those changes in its annual report for the year ended December 31, 2008.

 

At the expiration of the capital lease, September 30, 2008, the remaining gain of $1,332,345 was rolled into the gain on the sale assignment transaction with Lone Star of $624,047.  The total remaining gain to be amortized as of September 30, 2008 of $1,956,392 will be amortized over the life of the Lone Star operating lease, or 60 months.  The operating lease expires as of September 30, 2013.  This treatment is consistent with sale leaseback gain recognition rules.  For the years ended December 31, 2011 and 2010, the Company realized a gain on sale/leaseback of $391,278 for each year.

 

NOTE 4 – CERTIFICATE OF DEPOSIT

 

At December 31, 2011, the Company has $50,000 of restricted certificates of deposit (“CDs”). These investments are classified as either a current or long-term asset based on their maturity date. The securities generally have maturity dates of ten months to over one year. The restricted investments serve as collateral for an oil and gas operator license held by the Company’s wholly-owned subsidiary, Adino Exploration, LLC. The cash is held in custody by the issuing bank, is restricted as to withdrawal or use, and is currently invested in certificates of deposit. Income from these investments is paid to the Company at maturity of the certificates of deposit. These investments are classified as held-to-maturity and are recorded as either short-term or long-term on the balance sheet based on contractual maturity date and are recorded at amortized cost.  The Company’s securities are classified as held-to-maturity because the Company has the positive intent and ability to hold the securities to maturity.

 

NOTE 5 – ACCOUNTS RECEIVABLE

 

The Company uses an oil and gas gathering company for its oil sales. Each month, sales are recorded as the product is picked up by the gatherer and payments are made to the Company, the following month. The amounts accrued at December 31, 2011 and 2010 are for December production, to be paid in January 2012. Additionally, the Company advanced $10,000 to a business associate in December, 2011 for repayment in 2012.

 

   December 31, 2011   December 31, 2010 
         
Oil and gas gatherer receivable  $4,859   $9,615 
Advances   10,000    - 
Total  $14,859   $9,615 

 

 

NOTE 6 – EQUIPMENT

 

The following is a summary of this category:

 

   December 31, 2011   December 31, 2010 
         
Machinery and equipment  $528,720   $160,150 
Vehicles   60,927    47,427 
Leasehold improvements   37,076    23,789 
Office equipment   3,334    3,334 
Subtotal   630,057    234,700 
Less: Accumulated depreciation   (109,715)   (69,052)
Total  $520,342   $165,648 

 

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The useful life for leasehold improvements is the duration of the lease on the IFL fuel terminal, through September 30, 2013. Machinery and equipment, consisting primarily of oil field assets (see Note 10), has a useful life of seven years, vehicles’ useful life is five years and office equipment is being depreciated over three years.

 

NOTE 7 – PETRO ENERGY ACQUISITION PURCHASE PRICE ALLOCATION

 

The Company’s acquisition of the Petro Energy companies (see Note 1) included operating wells and fixed assets. The transaction, treated as a business combination, was valued under current guidance using fair value methods. To arrive at the acquired asset’s fair value, the valuation considered the value to be the price, in cash or equivalent, that a buyer could reasonably be expected to pay, and a seller could reasonably be expected to accept, if the business were exposed for sale on the open market for a reasonable period of time, with both buyer and seller being in possession of the pertinent facts and neither being under any compulsion to act.

 

The Company issued ten million (10,000,000) shares of common stock at closing as consideration for the companies. The stock price as of July 1, 2010 was $0.015 per common share, representing a value of $150,000.

 

The tangible assets acquired were valued based on the appropriate application of the market or cost approaches. The fair value was estimated at the depreciable value of the current replacement costs based on the age of the assets, assuming they are in good, working order. Additionally, the Company had an independent third party value the oil reserves for the Felix Brandt wells in Coleman, Texas.

 

A component of the acquisition agreement with PetroGreen Energy and AACM3, LLC gave the former owners of these companies the option to repurchase for $1.00 the assets held by the companies as of July 1, 2010 if the Company’s common stock price fails to reach $0.25 per share within three years of the original acquisition date. This contract clawback provision was valued at July 1, 2010 at $408,760.

 

The above valuations resulted in a goodwill calculation on acquisition of $7,139 at July 1, 2010.

 

Below is the acquisition summary including fair value of assets acquired, liabilities assumed and consideration given as of July 1, 2010:

 

   Fair Value at July 1, 2010 
Assets acquired:     
Tangible drilling costs  $155,700 
Proved oil and gas properties   71,060 
Machinery and equipment   324,861 
Total acquired asset fair value   551,621 
Less liability assumed:     
Contract clawback provision   (408,760)
Consideration - Common stock   (150,000)
Goodwill from acquisition  $7,139 

 

NOTE 8 – FAIR VALUE OF FINANCIAL INSTRUMENTS

 

The Company’s $50,000 CD is carried at cost, which approximates market. No gain or loss was realized on the security at December 31, 2011. The Company valued the Petro Energy acquisition, the current convertible note and warrant derivatives and the Company’s largest asset, goodwill, using Level 3 criterion, shown below. As of December 31, 2011, the valuations resulted in a gain on derivatives of $10,850, loss on contract clawback provision of $49,385 and goodwill impairment of $4,827 for a net loss of $53,859.

 

December 31, 2011                    
Description  Level 1   Level 2   Level 3   Total Realized
 Gain (Loss) due to
 Valuation
   Total Unrealized
 Gain (Loss) due to
 Valuation
 
                     
Marketable security - CD  $50,000   $-   $-   $-   $- 
                          
Goodwill   -    -    1,554,413    (4,827)   - 
                          
Notes payable  - derivative   -    -    133,235    14,541    - 
                          
Haag warrants - derivative   -    -    3,659    (3,691)   - 
                          
Contract clawback provision   -    -    386,739    49,385    - 
Total  $50,000   $-   $2,078,046   $53,859   $- 

 

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December 31, 2010                    
Description  Level 1   Level 2   Level 3   Total Realized
Gain (Loss) due to
 Valuation
   Total Unrealized
 Gain (Loss) due to
Valuation
 
                     
Goodwill  $-   $-   $1,566,379   $-   $- 
                          
Asher /BWME notes  - derivative   -    -    96,161    (60,323)   - 
                          
Haag warrants - derivative   -    -    7,350    (7,350)   - 
                          
Contract clawback provision             337,354    71,406    - 
Total  $-   $-   $2,007,244   $3,733   $- 

 

At December 31, 2010, the Company had $1,559,240 of goodwill on the balance sheet. Due to the sale of the Company’s interest in IFL in February 2012 (subsequent to the period covered by this report), the Company has recorded impairment of the goodwill to the extent of the loss on the transaction of $4,827.

 

NOTE 9 - NOTES RECEIVABLE / INTEREST RECEIVABLE

 

On November 6, 2003, Mr. Stuart Sundlun purchased 1,200 units of IFL from Adino. Part of the purchase price was a note from Mr. Sundlun dated November 6, 2003, bearing interest of 10% per annum in the amount of $750,000. This note was secured by 600 units of IFL being held in attorney escrow and released pursuant to the sales agreement.  The sales agreement provided that the unreleased units would revert to Adino if Mr. Sundlun did not acquire the remaining 600 units.

 

On August 7, 2006, IFL repurchased the units sold to Mr. Sundlun. The entire amount due from Mr. Sundlun and payable to Mr. Sundlun is reported at gross in the Company's financial statements. The right of offset does not officially exist even though it has been discussed. In accordance with current guidance, the Company did not net the note receivable against the note payable. Current guidance states “It is a general principal of accounting that the offsetting of assets and liabilities in the balance sheet is improper except where a right of setoff exists.” Although both parties agreed verbally that a net payment would be acceptable, no formal documentation exists of this verbal agreement.

 

The Company's position to not offset the amounts is further substantiated by current guidance as follows, due to lacking two of the four general criteria:  (1) The Company does not have a contractual right to offset even though that is the Company's intention and (2) Neither of the notes contains a specific right of offset.

 

In addition to the above facts, the note holder provided a separate written confirmation to the Company's auditors at December 31, 2011 and 2010 of both the note payable and note receivable balances, respectively.

 

The Company's net notes receivable and payable to and from Mr. Sundlun are a net payable of $750,000.

 

The 600 units of IFL are no longer held in escrow as the Company purchased all 1,200 units of IFL including the escrow units for $1,500,000 which is the value of the note payable.

 

The note receivable from Mr. Sundlun matured on November 6, 2008.  The Company extended the note’s maturity date to August 8, 2011 with no additional interest accrual to occur past November 6, 2008.  Due to the fact that there will be no interest accrued on the note going forward, the Company recorded a discount on the note principal of $179,671.  This amount will amortize until the note’s maturity in August 2011.

 

 Interest accrued on the Sundlun note receivable was $375,208 at December 31, 2011 and 2010.

 

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A schedule of the balances at December 31, 2011 and 2010 is as follows:

 

   December 31, 2011   December 31, 2010 
         
Sundlun, net of unamortized discount  $750,000   $703,430 
           
Total notes receivable  $750,000   $703,430 
Less:  current portion   (750,000)   (703,430)
Total long-term notes receivable  $-   $- 

 

NOTE 10 - OIL AND GAS PROPERTIES

 

Tangible drilling costs: The Company acquired tangible drilling equipment and proved oil and gas properties with the Petro Energy acquisition in July 2010. The tangible assets were valued based on the appropriate application of the market or cost approaches as of the date of acquisition. The fair value was estimated at the depreciable value of the current replacement costs based on the age and condition of the assets.

 

Since the Petro Energy acquisition, the Company has completed an extensive workover program on the original wells acquired. The Company has also drilled and completed 3 wells on the James Leonard lease during 2011. In late 2011, the Company drilled 5 new wells – 4 on the James Leonard lease and 1 on the Felix Brandt lease, financed by BlueRock Energy Capital II, LLC (“BlueRock”). (See Note 14 for additional discussion).

 

Proved oil and gas properties: As of December 31, 2011, the Company’s Felix Brandt leases include thirteen proved developed producing (PDP) wells and three saltwater disposal wells. According to the reserve analysis conducted by an independent engineering firm, the estimated discounted net cash flow on the Felix Brandt lease was $118,590 as of December 31, 2010. As a result of the Company’s workover and drilling programs during 2011, the estimated discounted net cash flow on the combined Felix Brandt and James Leonard leases are $951,247 as of December 31, 2011. Due to our significant net loss carryforward, we do not expect to pay any federal income taxes on future net revenues provided from the Felix Brandt lease production. Therefore, the pre-tax and after-tax estimate of discounted future net cash flows at December 31, 2011 are both $951,247.

 

Asset retirement obligation: The Company accounts for its asset retirement obligations by recording the fair value of a liability for an asset retirement obligation recognized in the period in which it was incurred if a reasonable estimate of fair value could be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset and allocated to operating expense using a systematic and rational method. As of December 31, 2011, the Company has recorded a net asset of $46,372 and related liability of $50,944. Accretion for the year ended December 31, 2011 was $3,704.

 

Impairment:  Current guidance requires that  unamortized capitalized costs (less certain adjustments) for each cost center  not exceed the cost ceiling, which is defined as the present value of future net revenues from estimated production of proved oil and gas reserves (plus certain adjustments). If adjusted unamortized costs capitalized within a cost center exceed the cost center ceiling, the excess is charged to expenses and separately disclosed during the period it occurs. The Company evaluated the carrying cost of the applicable oil producing properties and determined that the carrying value should be reduced by $47,481 for the year ended December 31, 2010. For the year ended December 31, 2011, the Company evaluated the carrying cost of the applicable oil producing properties and determined that the carrying value did not exceed the cost ceiling, therefore no adjustment was necessary for 2011. 

 

The oil and gas related asset values at December 31, 2011 and December 31, 2010 were as follows:

 

   December 31, 2011   December 31, 2010 
         
Tangible drilling costs  $409,334   $116,603 
Proved oil and gas properties   71,060    71,060 
Unproved oil and gas properties   280,602    59,060 
Asset retirement cost   46,372    35,821 
Impairment   (47,481)   (47,481)
Accumulated depletion   (73,260)   (20,724)
Total  $686,627   $214,339 

 

NOTE 11 – OTHER ASSETS

 

As the Company’s wells and lease holdings have increased, it has need for supplies on hand for lease and well repair and maintenance. At December 31, 2011, the Company had $25,001 in supplies and replacement parts available for use. The Company did not have need for supplies in 2010.

 

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NOTE 12 – CONSOLIDATION OF IFL AND GOODWILL

 

From the period of IFL’s inception to 2005, our ownership percentage in IFL was 60%. Our ownership increased to 80% during 2005 when our 20% partner withdrew from IFL and rescinded its investment. On August 7, 2006, we obtained the remaining 20% interest in IFL from Stuart Sundlun in consideration for a note payable as described in Note 9. This transaction was accounted for as a step acquisition. This step acquisition resulted in an additional $1,500,000 of goodwill as the fair value of the net assets acquired was determined by management to be zero and the consideration given as discussed above was the $1,500,000 note.

 

Adino evaluated the aggregate goodwill for impairment at December 31, 2010 and determined that the fair value of the reporting unit exceeds its carrying amount and was therefore, not impaired. At December 31, 2011, the Company had $1,559,240 of goodwill on the balance sheet. Due to the sale of the Company’s interest in IFL in February 2012 (subsequent to the period covered by this report), the Company has recorded impairment of the goodwill to the extent of the loss on the transaction of $4,827.

 

NOTE 13 – ACCRUED LIABILITIES / ACCRUED LIABILITIES – RELATED PARTY

 

Other liabilities and accrued expenses consisted of the following as of December 31, 2011 and 2010:

 

   December 31, 2011   December 31, 2010 
         
Accrued accounting and legal fees  $125,000   $115,000 
Customer deposits   110,000    110,000 
Property and payroll tax accrual   2,444    76,113 
Deferred lease liability   31,268    33,799 
Dividend payable   1,942    - 
Total accrued liabilities  $270,654   $334,912 
           
Accrued salaries-related party  $1,013,034   $909,960 
           
Asset retirement obligation  $50,944   $36,689 

 

Deferred lease liability:  The Lone Star lease is being expensed by the straight line method as required by current guidance, resulting in a deferred lease liability that will be extinguished by the lease termination date of September 30, 2013. The Company sold all of its membership interest in IFL to a third party on February 7, 2012 (subsequent to the period covered by this report).

 

Accrued salaries – related party:  This liability is due to certain officers and directors for prior years’ accrued compensation.  They have agreed to postpone payment if necessary, should the Company need capital it would otherwise pay these individuals.

 

NOTE 14 - NOTES PAYABLE

 

   December 31, 2011   December 31, 2010 
         
Note payable  - Stuart Sundlun, bearing interest of 10% per annum, due August 7, 2011  $1,500,000   $1,500,000 
Note payable - Gulf Coast Fuels, bearing interest of $25,000   436,380    275,000 
Demand note - Perales, non interest bearing, due May 31, 2011   -    50,000 
Note payable – Asher notes, net of discount of $50,986 and $26,807 at December 31, 2011 and December 31, 2010, respectively   119,514    30,693 
bearing interest of 8% per annum, due May 13, 2011 (balance $0.00 at 12/31/11; $57,500 at 12/31/10)          
bearing interest of 8% per annum, due February 16, 2012 (balance $5,000 at 12/31/11; $0.00 at 12/31/10)          
bearing interest of 8% per annum, due March 23,2012 (balance $53,000 at 12/31/11; $0.00 at 12/31/10)          
bearing interest of 8% per annum, due April 7, 2012 (balance $37,500 at 12/31/11; $0.00 at 12/31/10)          
bearing interest of 8% per annum, due June 12, 2012 (balance $37,500 at 12/31/11; $0.00 at 12/31/10)          
bearing interest of 8% per annum, due August 28, 2012 (balance $37,500 at 12/31/11; $0.00 at 12/31/10)          
Notes payable - BWME, bearing interest at 8% per annum, due September 2, 2013   400,000    400,000 
Notes payable - Schwartz group, bearing interest at 6%, due January 9, 2013   85,000    - 
Notes payable – BlueRock Energy Group, bearing interest at 18%, payable via production; $0.00 at 12/31/10)   379,854    - 
Note payable - GMAC, bearing interest of 11.7% per annum with 60 monthly payments of $895, due May 13, 2013   14,622    22,403 
Total notes payable  $2,935,370   $2,278,096 
Less: current portion   (2,445,363)   (1,864,251)
Long term note payable  $490,007   $413,845 

 

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On August 11, 2010, the Company issued a convertible promissory note to Asher Enterprises, Inc. (“Asher”), in the amount of $57,500. The note had a maturity date of May 13, 2011 and an annual interest rate of eight percent (8%) per annum. The holders have the right from and after the date of issuance, and until any time until the note is fully paid, to convert any outstanding and unpaid principal portion of the note, and accrued interest, into fully paid and non-assessable shares of common stock. The note has an initial conversion price of fifty eight percent (58%) of the 3 lowest closing bid prices for the 10 days preceding the conversion date and full reset provision. The note’s convertible feature was valued and resulted in a debt discount of $35,838, which is being amortized over the nine month note life, using the straight line method. In this case, using the straight line method approximates the effective interest method, given the short time to maturity.

 

With the Asher notes, the Company has the right to redeem the notes within 90 days from the date of issuance for 135% of the redemption amount and accrued interest, from days 91-120, the Company has the right to redeem the notes for 145% of the redemption amount and accrued interest, and from days 121-180, the Company has the right to redeem the notes for 150% of the redemption amount and accrued interest.  

 

On September 2, 2010, the Company issued convertible promissory notes to investors in the amount of $400,000, to fund financing and start-up costs of the recent Petro Energy acquisition. The notes have a maturity date of September 2, 2013, with accrued interest paid quarterly and an annual interest rate of eight percent (8%) per annum. The holders have the right from and after the date of issuance, and until any time until the note is fully paid, to convert any outstanding and unpaid principal portion of the note, and accrued interest, into fully paid and non-assessable shares of common stock. The note has a fixed conversion price of $0.10. In December 2010, the former owner of AACM3, LLC transferred the certificate of deposit securing the P5 bond financial assurance for the Company’s oil and gas operator’s license to the Company.  The agreement calls for the Company to pay a total of $60,000 for the transfer, which was completed in the second quarter of 2012.

 

On January 10, 2011, the Company issued convertible promissory notes to investors in the amount of $272,500, to fund drilling activities associated with the recent Petro Energy acquisition. The notes have a maturity date of January 9, 2013, with interest accrued and paid at the option of the holder at an annual interest rate of six percent (6%) per annum. The holders have the right from and after the date of issuance, and until any time until the note is fully paid, to convert any outstanding and unpaid principal portion of the note, and accrued interest, into fully paid and non-assessable shares of common stock. The note has a fixed conversion price of $0.35. During December 2011, the Company offered to convert the notes into shares of the Company’s Class B Preferred Stock, Series 3. Three of the investors chose to convert their notes, totaling $187,500 into shares of the preferred stock. The remaining notes of $62,500 and $22,500 remain outstanding at December 31, 2011.

 

During the first quarter of 2011, Asher converted $34,000 of the notes into the Company’s common stock, resulting in an issuance of 1,862,833 shares to Asher.  During the second quarter of 2011, Asher converted the remaining balance of $23,500 into the Company’s common stock, resulting in an issuance of 2,036,820 shares to Asher.  No amounts were converted during the third quarter, 2011. During the fourth quarter of 2011, Asher converted $48,000 into the Company’s common stock, resulting in an issuance of 2,664,063 shares to Asher. See Note 17 for a detailed description of each conversion.

 

During the second quarter of 2011, the Company issued two nine-month convertible promissory notes to Asher in the amount of $53,000 each. The notes have maturity dates of February 16, 2012 and March 23, 2012 and an annual interest rate of eight percent (8%) per annum. The holders have the right from and after the date of issuance, and until any time until the note is fully paid, to convert any outstanding and unpaid principal portion of the note, and accrued interest, into fully paid and non-assessable shares of common stock. The note has an initial conversion price of sixty five percent (65%) of the three lowest closing bid prices for the ten days preceding the conversion date. The notes’ convertible features were valued and resulted in debt discounts of $23,918 and $23,998 respectively, which is being amortized over the nine month note life, using the straight line method. In this case, using the straight line method approximates the effective interest method, given the short time to maturity.

 

On October 14, 2011, the Company entered into a production agreement with BlueRock Energy Capital II, LLC (“BlueRock”). Under the production agreement, BlueRock funded Adino with $410,000 for the drilling of five oil wells on the Company’s Leonard and Felix Brandt leases and for working capital. Under the terms of the production agreement, BlueRock will be entitled to 65% of the net revenue interest of the wells until BlueRock receives $410,000 plus an 18% return on investment. These monies are to be paid as the Company receives production payments on the new wells. After payment of this amount, BlueRock will receive a 3% overriding royalty interest on the wells. At December 31, 2011, the balance on the BlueRock agreement was $379,854.

 

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During the third quarter of 2011, the Company issued two nine-month convertible promissory notes to Asher in the amount of $37,500 each. The notes have maturity dates of April 17, 2012 and June 12, 2012 and an annual interest rate of eight percent (8%) per annum. The holders have the right from and after the date of issuance, and until any time until the note is fully paid, to convert any outstanding and unpaid principal portion of the note, and accrued interest, into fully paid and non-assessable shares of common stock. The note due April 17, 2012 has an initial conversion price of sixty five percent (65%) of the three lowest closing bid prices for the ten days preceding the conversion date. The note due June 12, 2012 has an initial conversion price of fifty six percent (56%) of the three lowest closing bid prices for the ten days preceding the conversion date. The notes’ convertible features were valued and resulted in debt discounts of $15,943 and $21,720 respectively, which is being amortized over the nine month note life, using the straight line method. In this case, using the straight line method approximates the effective interest method, given the short time to maturity.

 

On November 22, 2011, the Company issued a nine-month convertible promissory note to Asher in the amount of $37,500. The note has a maturity date of August 28, 2012 and an annual interest rate of eight percent (8%) per annum. The holders have the right from and after the date of issuance, and until any time until the note is fully paid, to convert any outstanding and unpaid principal portion of the note, and accrued interest, into fully paid and non-assessable shares of common stock. The note has an initial conversion price of fifty eight percent (58%) of the three lowest closing bid prices for the ten days preceding the conversion date. The note’s convertible feature was valued and resulted in a debt discount of $21,477, which is being amortized over the nine month note life, using the straight line method. In this case, using the straight line method approximates the effective interest method, given the short time to maturity.

 

The table below reflects the aggregate principal maturities of long-term debt for years ended December 31:

 

    Principal 
      
2012   $2,445,363 
2013    490,007 
2014    - 
2015    - 
2016    - 
Total   $2,935,370 
        

NOTE 15 - CONTRACT CLAWBACK PROVISION

 

A component of the acquisition agreement with PetroGreen Energy and AACM3, LLC gave the former owners of these companies the option to repurchase for $1.00 the assets held by the companies as of July 1, 2010 if the Company’s common stock price fails to reach $0.25 per share within three years of the original acquisition date. This contract clawback provision was valued at July 1, 2010 at $408,760 and was revalued at December 31, 2010 at $337,354 resulting in a gain on change in clawback valuation of $71,406 at December 31, 2010. The clawback valuation at December 31, 2011 was $386,739, resulting in a loss on change in clawback valuation of $49,385 at December 31, 2011.

 

NOTE 16 – DERIVATIVE LIABILITY

 

Based on current guidance, the Company concluded that the convertible notes payable to Asher referred to in Note 14 were required to be accounted for as a derivative. This guidance requires the Company to bifurcate and separately account for the conversion features of the convertible notes issued as embedded derivatives.

 

With convertible notes in general, there are three primary events that can occur: the holder can convert the note into stock; the Company can force conversion of the convertible note; or the Company can default on the note or liquidate. The model analyzed the underlying economic factors that influenced which of these events would occur, when they were likely to occur, and the specific terms that would be in effect at the time (i.e. interest rates, stock price, conversion price etc.). Projections were then made on these underlying factors which led to a set of potential scenarios. Probabilities were assigned to each of these scenarios based on management projections. This led to a cash flow projection and a probability associated with that cash flow. A discounted weighted average cash flow over the various scenarios was completed, and it was compared to the discounted cash flow of a hypothetical one year 0% debt instrument without the embedded derivatives, thus determining a value for the compound embedded derivatives at the date of issue.

 

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Derivative financial instruments are initially measured at their fair value.  For  derivative  financial  instruments  that are accounted for as liabilities,  the derivative  instrument is initially recorded at its fair value and is then  re-valued at each reporting  date,  with changes in the fair value  reported  as charges  or credits to income.

 

The Company used a lattice model that values the compound embedded derivatives based on a probability weighted discounted cash flow model. This model is based on future projections of the various potential outcomes. The Asher notes contained embedded derivatives that were analyzed. Certain features of the Asher notes were incorporated into the derivative valuation model, including the conversion feature with a reduction of the conversion rate based upon future below-market issuances and the redemption options.

 

The structure of the Asher notes caused two other financial instruments held by the Company to be deemed derivatives: The BWME notes and the Haag warrants. Both were valued as derivatives as of the date of the Asher note issuance (Haag warrants) or date of issuance (BWME notes) and revalued as of December 31, 2011.

 

Below is detail of the derivative liability balances as of December 31, 2011 and December 31, 2010.

 

Derivative Liability  December 31, 2010   Additions   Increase
(Decrease)
from valuation
   December 31, 2011 
                 
Asher note / BWME notes  $96,161   $107,059   $(69,986)  $133,234 
                     
Haag warrants   7,350    -    (3,690)   3,660 
Total  $103,511   $107,059   $(73,676)  $136,894 

 

The net increase of $33,383 is split between changes to derivative liability due to new note addition and conversion of $107,059, a reduction of $62,826 to additional paid-in-capital for the derivative reduction attributable to the Asher note conversions discussed in Notes 12 and 15.  The remaining $10,850 is reflected as gain on derivatives in the statement of operations.

 

NOTE 17 – STOCK

 

COMMON STOCK

 

The Company's common stock has a par value of $0.001. There were 50,000,000 shares authorized as of December 31, 2007.  At the Company’s January 2008 shareholder meeting, the shareholders voted to increase the authorized common stock to 500,000,000 shares.  As of December 31, 2011 and December 31, 2010, the Company had 125,574,295 and 107,260,579 shares issued and outstanding, respectively.

 

On February 2, 2010, the Board approved a stock issuance of 250,000 shares of restricted common stock each to Michael Turchi and Mountaintop Development, Inc. for services rendered to the Company. The issuance resulted in an expense to the Company of $5,700, based on the stock’s market price at the date of issuance.

 

The Company issued 10,000,000 shares of stock to the sellers in the Petro Energy acquisition. The Company acquired 100% of the membership interests of both companies as of July 1, 2010. The transaction resulted in stock expense to the Company of $150,000, based on the stock’s market price at the date of issuance. See Notes 1, 6, 9, 13, and Item 1 for a thorough discussion of the acquisition transaction.

 

On September 7, 2010, the Board approved a stock issuance of 2,000,000 shares of restricted common stock to Vulcan Advisors, LLC for consulting services performed for the Company. The issuance resulted in an expense to the Company of $70,000, based on the stock’s market price at the date of issuance.

 

During November 2010, the Board approved a stock issuance of 500,000 shares each to its three members for services rendered.  The total issuance of 1,500,000 shares resulted in expense to the Company of $46,500, based on the stock’s market price at the date of issuance.

 

On February 22, 2011, Asher converted $10,000 of its note into 465,116 shares of the Company’s common stock. The conversion resulted in an increase of additional paid-in-capital of $9,535 due to the reduction of the associated liability.

 

On March 8, 2011, Asher converted $12,000 of its note into 603,015 shares of the Company’s common stock. The conversion resulted in an increase of additional paid-in-capital of $11,397 due to the reduction of the associated liability.

 

On March 22, 2011, Asher converted $12,000 of its note into 794,702 shares of the Company’s common stock. The conversion resulted in an increase of additional paid-in-capital of $11,205 due to the reduction of the associated liability.

 

On April 4, 2011, Asher converted $15,000 of its note into 1,219,512 shares of the Company’s common stock. The conversion resulted in an increase of additional paid-in-capital of $13,780 due to the reduction of the associated liability.

 

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On April 12, 2011, Asher converted $8,500 of its note into 817,308 shares of the Company’s common stock. The conversion resulted in an increase of additional paid-in-capital of $7,683 due to the reduction of the associated liability.

 

During the fourth quarter 2011, Asher converted $48,000 of its notes into 2,664,063 shares of the Company’s common stock. The conversions resulted in an increase of additional paid-in-capital of $45,336 due to the reduction of the associated liability.

 

All note conversions were within the terms of the agreement. 

 

On August 9, 2011, the Company entered into a consulting agreement with RKM Capital for consulting and investor relations services.  The Company paid $2,500 and issued ten million, seven hundred fifty thousand (10,750,000) shares of restricted common stock, with a market price of $0.02 per share, resulting in expense to the Company of $225,750.

 

On September 16, 2011, the Board of Directors issued 250,000 shares of restricted common stock to each of its directors as compensation for 2011 director’s fees.  The market price on the date of grant was $0.022, resulting in expense to the Company of $11,000.

 

On September 16, 2011, the Board of Directors granted 500,000 shares of restricted common stock to the Company’s controller, Nancy Finney, for services rendered.  Ms. Finney relinquished the 500,000 fully vested options granted to her in 2007 in this transaction.  Current guidance required the options to be revalued as of the day prior to the share grant.  Using the Black-Scholes valuation model and an expected life of 1 year (remaining option life), volatility of 226%, and a discount rate of .09%, the Company has determined the aggregate value of the 500,000 options to be $5,643.  The market price of the issued stock on date of grant was $0.022, resulting in stock expense to the Company of $11,000.  The Company recorded an expense of $5,357 (market value – option value) on the transaction.

 

As a result of the above common stock issuances, there were 125,574,295 shares issued and outstanding as of December 31, 2011.

 

PREFERRED STOCK

 

In 1998, the Company amended its articles to authorize Preferred Stock. There are 20,000,000 shares authorized with a par value of $0.001. The shares are non-voting and non-redeemable by the Company. The Company further designated two series of its Preferred Stock: "Series 'A' $12.50 Preferred Stock" with 2,159,193 shares of the total shares authorized and "Series "A" $8.00 Preferred Stock," with the number of authorized shares set at 1,079,957 shares.

 

Any holder of either series may convert any or all of such shares into shares of common stock of the Company at any time. Said shares shall be convertible at a rate equal to three (3) shares of common stock of the Company for each one (1) share of Series "A" $12.50 Preferred Stock. The Series "A" 12.50 Preferred Stock shall be convertible, in whole or in part, at any time after the common stock of the Company shall maintain an average bid price per share of at least $12.50 for ten (10) consecutive trading days.

 

Series "A" $8.00 Preferred Stock shall be convertible at a rate equal to three (3) shares of common stock of the Company for each one (1) share of Series "A" $8.00 Preferred Stock. The Series "A" $8.00 Preferred Stock shall be convertible, in whole or in part, at any time after the common stock of the Company shall maintain an average bid price per share of at least $8.00 for ten (10) consecutive trading days.

 

The preferential amount payable with respect to shares of either Series of Preferred Stock in the event of voluntary or involuntary liquidation, dissolution, or winding-up, shall be an amount equal to $5.00 per share, plus the amount of any dividends declared and unpaid thereon.

 

As of December 31, 2011, the Company has also designated two series of Class B Preferred Stock.

 

The number of authorized shares of Class B Preferred Stock Series 1 is 666,680 shares. At any time after six months from the date of issuance of Class B Preferred Stock Series 1, any holder may convert up to 25% of such holder’s initial holdings (i.e. before taking into account any prior conversions, but taking into account any sales or transfers) of Class B Preferred Stock Series 1 into fully paid and nonassessable shares of common stock of the Company at the rate of one hundred (100) shares of common stock per share of Class B Preferred Stock Series 1. Every month thereafter, any holder of Class B Preferred Stock Series 1 may convert up to 12.5% of such stockholder’s initial holdings of Class B Preferred Stock Series 1 (i.e. before taking into account any prior conversions, but taking into account any sales or transfers) into fully paid and nonassessable shares of common stock of the Company at the rate of one hundred (100) shares of common stock per share of Class B Preferred Stock Series 1. Any such conversion may be effected by giving to the Secretary of the Company written notice of conversion, accompanied by the surrender of the certificate(s) of the stock to be converted, duly endorsed, along with any other information or documents reasonably requested by the Secretary to effect the conversion. The shares of Class B Preferred Stock Series 1 shall not have any voting rights. Any outstanding shares of Class B Preferred Stock Series 1 may be redeemed by the Company, at the Company’s option, at any time for $15.00 per share.

 

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On November 3, 2011, The Company acquired all unencumbered assets owned by two limited partnerships managed by Ashton Oilfield Services, LLC (“Ashton”). The assets were purchased for one million five hundred thousand dollars ($1,500,000) and the Company issued 100,000 shares of Class B Preferred Stock Series 1 to Ashton. The assets were valued based on fair market value for similar assets in good, working condition.

 

At December 31, 2011, there were 100,000 shares of Class B Preferred Stock Series 1 issued and outstanding. No shares were issued or outstanding at December 31, 2010.

 

The number of authorized shares of Class B Preferred Stock Series 3 is 18,570 shares. The issue price for Class B Preferred Stock Series 3 is $35.00. The holders of Class B Preferred Stock Series 3 shall be entitled to receive a quarterly dividend equal to 2.5% of the issue price of each share. The dividends shall be paid quarterly, when as and if declared payable by the Company’s Board of Directors from funds legally available for the payment thereof. If in any quarter the Company does not pay any accrued dividends, such dividends shall cumulate. Interest shall not be paid on cumulated dividends. Each share of Class B Preferred Stock Series 3 shall rank on the same parity with each other share of preferred stock, irrespective of series, with respect to dividends at the respective fixed or maximum rate for such series. Any holder of Class B Preferred Stock Series 3 may convert, at any time, any or all shares held into common stock of the Company. Each Class B Preferred Stock Series 3 share held may be converted into one hundred (100) fully paid and nonassessable shares of common stock of the Company at the conversion rate of $0.35 per common stock.

 

On December 10, 2011, three of the Schwartz investors, each holding a note for $62,500, converted their notes into 1,786 shares of the Company’s Class B Preferred Stock Series 3, for a total issuance of 5,358 shares. Additionally, each investor invested an additional $50,000 in the Company through the purchase of 1,428 shares of Class B Preferred Stock Series 3 shares, for a total issuance of 4,284 shares.

 

At December 31, 2011, there were 9,642 shares of Class B Preferred Stock Series 3 issued and outstanding. No shares were issued or outstanding at December 31, 2010.

 

DIVIDENDS

 

Dividends for Class B Preferred Stock Series 3 are cumulative. The holders of Class B Preferred Stock Series 3 shall be entitled to receive a quarterly dividend equal to 2.5% of the issue price of each share. The dividends shall be paid quarterly, when as and if declared payable by the Company’s Board of Directors from funds legally available for the payment thereof. If in any quarter the Company does not pay any accrued dividends, such dividends shall cumulate. Interest shall not be paid on cumulated dividends.

 

Dividends for Class A Preferred Stock and Class B Series 1 Preferred Stock are non-cumulative, however, the holders of such series, in preference to the holders of any common stock, shall be entitled to receive, as and when declared payable by the Board of Directors from funds legally available for the payment thereof, dividends in lawful money of the United States of America at the rate per annum fixed and determined as herein authorized for the shares of such series, but no more.

 

Dividends for Class A Preferred Stock are payable quarterly on the last days of March, June, September, and December in each year with respect to the quarterly period ending on the day prior to each such respective dividend payment date. In no event shall the holders of Class A Preferred Stock receive dividends of more than percent (1%) in any fiscal year, and each share shall rank on parity with each other share of preferred stock, irrespective of class or series, with respect to dividends at the respective fixed or maximum rates for such series.

 

At December 31, 2011, the Company recorded a dividend payable for the Class B Preferred Stock Series 3 shares of $1,942, for those shares issued in the Schwartz debt conversion, discussed above.

 

NOTE 18 - STOCK OPTIONS / STOCK WARRANTS

 

In September 2007, the Company entered into a consulting agreement with Small Cap Support Services, Inc. (“Small Cap”) to provide investor relations services.  In addition to monthly compensation, Small Cap was entitled to 500,000 options, vesting ratably over 8 quarters through August 30, 2009, priced at 166,667 shares at $0.15, $0.25, and $0.35 each.  Using the Black-Scholes valuation model and an expected life of 3.5 years, volatility of 271.33%, and a discount rate of 4.53%, the Company determined the aggregate value of the 500,000 seven year options to be $59,126. The options became fully expensed and vested as of June 30, 2009. All options are outstanding at December 31, 2011.

 

In November 2007, the Company entered into an agreement with Nancy Finney, the Company’s Controller. In addition to monthly contract payments, Ms. Finney was entitled to 500,000 options, vesting over 24 months as certain milestones were met. In accordance with current guidance, these options were expensed at their fair value over the requisite service period.  Using the Black-Scholes valuation model and an expected life of 2.5 years, volatility of 276.75%, and a discount rate of 4.16%, the Company determined the aggregate value of the 500,000 options to be $23,949.  The options became fully expensed and vested as of September 30, 2009.

 

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On September 16, 2011, the Board of Directors granted 500,000 shares of restricted common stock to Ms. Finney for services rendered.  Ms. Finney relinquished the 500,000 fully vested options granted to her in 2007 within this transaction.  Current guidance required the options to be revalued as of the day prior to the share grant.  Using the Black-Scholes valuation model and an expected life of 1 year (remaining option life), volatility of 226%, and a discount rate of .09%, the Company has determined the aggregate value of the 500,000 options to be $5,643.  The market price of the issued stock on date of the grant was $0.022, resulting in stock expense to the Company of $11,000.  The Company recorded an expense of $5,357 (market value – option value) on the transaction.

 

NOTE 19 – EARNINGS PER SHARE

 

The table below sets forth the computation of basic and diluted net income (loss) per share for the years ended December 31, 2011 and 2010.

 

   For the years ended December 31, 
   2011   2010 
Numerator:          
(Loss) from continuing operations  $(1,856,714)  $(674,888)
           
Income from discontinued operations  $548,041   $397,086 
           
Basic net income (loss)  $(1,308,673)  $(277,802)
Diluted net income (loss)  $(1,308,673)  $(277,802)
           
Denominator:          
Basic weighted average common shares outstanding   114,945,684    99,512,634 
Effect of dilutive securities          
Convertible note - Asher   5,089,194    1,280,990 
Dilutive weighted average common shares outstanding   120,034,878    100,793,624 
           
Net (loss) per share, basic and fully diluted – continuing operations  $(0.02)  $(0.01)
Net income per share, basic and fully diluted – continuing operations  $0.00   $0.00 
           
Basic net income (loss) per share  $(0.01)  $(0.00)
Diluted net income (loss) per share  $(0.01)  $(0.00)

 

As of December 31, 2011, Adino had 125,574,295 shares outstanding, with no shares payable outstanding.  The Company uses the treasury stock method to determine whether any outstanding options or warrants are to be included in the diluted earnings per share calculation.

 

As of December 31, 2011, Adino had 500,000 earned options outstanding to a former consultant, exercisable between $0.15 to $0.35 each.  Using an average share price for the year ended December 31, 2011 of $0.029, the options result in no additional dilution to the Company.

 

The Company calculated the dilutive effect of the convertibility of the outstanding notes, resulting in additional weighted average share additions of 5,089,194 for the year ended December 31, 2011. The effect on earnings per share from the Company’s BWME and Schwartz convertible notes was excluded from the diluted weighted average shares outstanding because the conversion of these instruments would have been non-dilutive since the strike price is above the market price for our stock.

 

The dilutive effect of convertible instruments on earnings per share is not presented in the consolidated statements of operations for periods with a net loss.

 

37
 

 

NOTE 20 – DEFERRED INCOME TAX

 

The Company uses the asset and liability approach to account for income taxes. Under this method, deferred tax assets and liabilities are recognized for the expected future tax consequences of differences between the carrying amounts of assets and liabilities and their respective tax bases using tax rates in effect for the year in which the differences are expected to reverse. A valuation allowance is provided when it is more likely than not that some portion or all of the deferred tax assets will not be realized. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period when the change is enacted.

 

On January 1, 2007, the Company adopted an accounting standard which clarifies the accounting for uncertainty in income taxes recognized in financial statements. This standard provides guidance on recognizing, measuring, presenting and disclosing in the financial statements uncertain tax positions that a company has taken or expects to take on a tax return. See Note 20 for further information related to the Company’s accounting for uncertainty in income taxes.

 

During both 2011 and 2010, the Company incurred a net loss and therefore had no tax liability.  The Company does not have any material uncertain income tax positions.  As a result, the net deferred tax asset generated by the loss carry forward has been fully reserved.  The cumulative net operating loss carry forward is approximately $12,459,913 and $11,245,582 at December 31, 2011 and 2010, respectively, and will expire in the years 2020 through 2030.

 

 At December 31, 2011 and 2010, the deferred tax assets consisted of the following:

 

   December 31, 2011   December 31, 2010 
         
Net operating loss  $4,236,370   $3,823,498 
Less: Valuation allowance  $(4,236,370)  $(3,823,498)
Net deferred tax asset  $-   $- 

 

NOTE 21 – SALE OF ADINO DRILLING, LLC

 

On March 31, 2011, the Company sold the membership shares of Adino Drilling, LLC to a related party.  Under the terms of the agreement, the Company realized a reduction in accrued liability of $100,000 and acquired a $500,000 six year, 5.24% interest note receivable, for a total sale price of $600,000.  The sale resulted in a gain to the Company of $247,376; however the transaction’s related party note of $500,000 is not allowed for reporting purposes, therefore the Company realized a reportable loss of $252,624. 

 

With the sale of Adino Drilling, LLC, the $7,139 of goodwill resulting from the original PetroGreen acquisition, discussed in Note 7 was written off.  The transaction has been accounted for as a discontinued operation.

 

Below are the asset and liability values for Adino Drilling, LLC at March 31, 2011 and December 31, 2010:

 

   Assets disposed at
March 31, 2011
   December 31, 2010 
         
Cash  $100   $2,899 
Fixed assets, net of depreciation of $34,837 and $21,186 at March 31, 2011 and December 31, 2010, respectively   350,702    354,415 
Total assets   350,802    357,314 
           
Accounts payable   5,317    44,472 
Accounts payable - related party   -    412 
Total liabilities   5,317    44,884 
           
Net assets - discontinued operations  $345,485   $312,430 

 

NOTE 22 – SALE OF INTERCONTINENTAL FUELS, LLC

 

On February 7, 2012 (subsequent to the period covered by this report), Adino sold all of its membership interest in IFL to Pomisu XXI S.L. (“Buyer”). The purchase price paid by the Buyer was $900,000, paid in two installments with the first installment of $244,824.97 paid on February 7, 2012, and the balance due not later than May 7, 2012. The balance of the purchase price shall be computed as follows: $900,000 minus $244,842.97 (initial installment) minus any IFL liabilities plus any cash on deposit with Regions Bank for the benefit of IFL or cash on deposit with J.P. Morgan Bank for the benefit of the Company. 

 

Within the purchase, the buyer acquired no assets, besides the membership interest in IFL.

 

38
 

 

The Buyer agreed to assume the following liabilities in the transaction:

 

Description  Amount 
      
Accounts payable  $106,520 
G J Capital judgment   437,154 
Due to related party   1,500 
Prepaid rent deposit   110,000 
Total  $655,175 

 

The December 31, 2011 IFL balance sheet (unconsolidated) is presented below:

 

   December 31, 2011 
Assets     
Cash  $107,544 
Fixed Assets net of depreciation   6,281 
Total assets  $113,825 
      
Liabilities     
Accounts payable  $183,634 
Accrued liabilities   141,267 
Deferred gain on sale/leaseback   179,858 
Due to G J Capital   436,380 
Total liabilities   941,139 
      
Equity     
Additional paid-in-capital   1,870,100 
Distributions   (628,226)
Retained earnings   (2,600,768)
Net income   531,580 
Total equity   (827,314)
Total liabilities and equity  $113,825 

 

With knowledge of the sale at the filing date, the operating income of IFL must be presented as discontinued operations. For comparison purposes, 2010 operations are presented consistently. The net income detail for the years ended December 31, 2011 and 2010 for IFL (unconsolidated) is presented below:

 

   IFL   IFL 
   for the year ended   for the year ended 
   12/31/2011   12/31/2010 
Revenues:          
Terminal operations revenue  $1,824,000   $1,944,666 
           
Operating expenses:          
Cost of product sales   -    236,503 
Terminal management   402,270    400,360 
General and administrative   504,159    573,984 
Legal and professional   127,207    72,372 
Consulting fees   180,024    719,387 
Repairs   100    5,929 
Depreciation expense   22,237    10,545 
Total operating expenses   1,235,997    2,019,080 
           
Operating income (expense)   588,003    (74,414)
           
Other income (expense)          
Interest income   276    99 
Interest expense   (7,809)   (10,295)
Gain on debt conversion   -    65,000 
Gain from lawsuit/sale leaseback   391,278    391,278 
Other income   (151,665)   25,418 
Total other income and expense   232,080    471,500 
         - 
Net income  $820,083   $397,086 

 

39
 

 

NOTE 23 – NON-CASH INVESTING AND FINANCING ACTIVITIES

 

The note receivable from Mr. Sundlun matured on November 6, 2008.  The Company extended the note’s maturity date to August 8, 2011 with no additional interest accrual to occur past November 6, 2008.  Due to the fact that there will be no interest accrued on the note going forward, the Company recorded a discount on the note principal of $179,671 in 2010.  This amount was fully amortized as of August 2011. The Company is currently re-negotiating the notes receivable and payable with Mr. Sundlun.

 

NOTE 24 – LAWSUIT SETTLEMENT – IFL TERMINAL

 

In 2005, a lawsuit was filed putting IFL’s ownership of the terminal in question. At the time of these lawsuits, Adino’s note to North American Reserve Corporation (“NARC”) was in default. The amount outstanding under the note was $725,733. In addition, Adino’s notes and debentures to Dr. David Zehr in the principal amount of $3,100,000 plus accrued interest were in default.

 

On March 23, 2007, the Company settled all litigation with all parties to this transaction. In the settlement, IFL released its claim of ownership of the terminal in favor of NARC. 17617 Aldine Westfield Road, LLC, an entity controlled by Dr. Zehr, then purchased the terminal from NARC for total consideration of $1.55 million ($150,000 in cash and a $1.4 million note). Simultaneously with these transactions, IFL agreed to lease the terminal from 17617 Aldine Westfield Road, LLC for 18 months at $15,000 per month with an option to purchase the terminal for $3.55 million at the end of the lease. In return for the lease, all debentures owed to Dr. Zehr were extinguished.

 

As a result of these transactions, all claims by and against all parties except Mr. Peoples were released. In addition, all liens pending on IFL’s property were released. The complete lawsuit settlement resulted in a net gain to Adino and IFL of $1,480,383.  Due to the terminal sale / leaseback transaction, the gain is being recognized over the life of the capitalized asset or 15 years.  Gain recognized for 2010 and 2011 was $391,278 for each year.

 

NOTE 25 – LAWSUIT SETTLEMENT – G J CAPITAL

 

On March 15, 2010, G J Capital, Ltd. (“G J Capital”) filed suit against Adino Energy Corporation and IFL in the 129th Judicial District Court of Harris County, Texas. G J Capital’s claim relates to a repurchase agreement whereby IFL sold to G J Capital certain assets for $250,000 and retained the ability to repurchase the assets in sixty days by paying to G J Capital the amount of $275,000. G J Capital’s petition alleged claims of breach of contract, money had and received, and fraudulent misrepresentation. G J Capital later amended its petition to allege that certain of Adino’s directors and officers (Mr. Timothy Byrd and Mr. Sonny Wooley) fraudulently transferred assets of Adino and/or IFL. G J Capital has also alleged that Mr. Wooley and Mr. Byrd are the  alter ego of Adino and IFL, and/or that Adino and/or IFL are alter egos of one another. G J Capital also alleged fraudulent conduct by one or more of the defendants.

 

Adino, IFL, Mr. Byrd and Mr. Wooley countersued G J Capital and filed third-party claims against CapNet Securities Corporation (“CapNet”), Daniel L. Ritz, Jr. (“Ritz”), Gulf Coast Fuels, Inc. (“Gulf Coast”) and Paul Groat (“Groat”), alleging that they conspired to damage IFL and Adino by involving it in the transaction described above. In this action, Adino, IFL, Mr. Byrd and Mr. Wooley contended that Ritz, CapNet, Gulf Coast, and Groat were involved together for the common, improper scheme to cause IFL immense financial hardship so that Gulf Coast could acquire the fuel terminal currently leased by IFL at an unfairly low price; that as part of this conspiracy they also effected a settlement of the Gulf Coast claim (which, if true, would mean that G J Capital acquired no claim at all against any of the defendants); and that in addition or in the alternative, even if G J Capital acquired some cognizable interest against IFL, Adino, IFL, Byrd and Wooley are entitled to indemnification by and contribution by Ritz, CapNet, Gulf Coast, and Groat.

 

40
 

 

In December 2011, G J Capital dismissed its claims against Mr. Byrd and Mr. Wooley. Also in December 2011, the court rendered judgment for G J Capital and against Adino and IFL in the amount of $250,000, plus $152,987.50 in attorneys’ fees, $9,300.00 in court costs, plus $20,616.44 in prejudgment interest. Interest will continue to accrue on the judgment at the rate of $34.25 until satisfied. The Company did not appeal this judgment. The Company accrued all fees and interest related to the judgment as of December 31, 2011. The total accrual expensed to IFL was $437,155. This amount was assumed by the buyer of IFL in the February 2012 sale.

 

NOTE 26 – CONCENTRATIONS

 

The Company has one customer for its oil and gas revenues.

 

   Year Ended
December 31,
2011
   %   Year Ended
December 31,
2010
   % 
                     
Customer A  $277,917    100%  $58,107    100%

 

The same customer discussed above represented 100% of outstanding receivables for both years ended December 31, 2011 and 2010.

 

NOTE 27 – SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (Unaudited)

 

In January 2010, the FASB issued an ASU to amend existing oil and gas reserve accounting and disclosure guidance to align its requirements with the SEC’s revised rules discussed in Note 1.  The significant revisions involve revised definitions of oil and gas producing activities, changing the pricing used to estimate reserves at period end to a twelve month arithmetic average of the first day of the month prices and additional disclosure requirements.  In contrast to the SEC rule, the FASB does not permit the disclosure of probable and possible reserves in the supplemental oil and gas information in the notes to the financial statements. The amendments are effective for annual reporting periods ending on or after December 31, 2009.  Application of the revised rules is prospective and companies are not required to change prior period presentation to conform to the amendments.  Application of the amended guidance has only resulted in changes to the prices used to determine proved reserves at December 31, 2009.  The new guidelines have expanded the definition of proved undeveloped reserves that can be recorded from an economic producer.  The opportunity to prove reasonable certainty for spacing areas located more than one direct development spacing area from economic producer did not impact or prove undeveloped reserves.

 

The Company follows the guidelines prescribed in ASC Topic 932 for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves.  Future cash inflows and future production and development costs are determined by applying prices and costs, including transportation, quality, and basis differentials, to the year-end estimated quantities of oil and gas to be produced in the future.  The resulting future net cash flows are reduced to present value amounts by applying a ten percent annual discount factor.  Future operating costs are determined based on estimates of expenditures to be incurred in producing the proved oil and as reserves in place at the end of the period using year-end costs and assuming continuation of existing   conditions, plus Company overhead incurred.  Future development costs are determined based on estimates of capital expenditures to be incurred in developing proved oil and gas reserves.

 

The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC.   The assumptions do not necessarily reflect the Company’s expectations of actual revenues to be derived from those reserves, nor their present value.  The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these reserve quantity estimates are the basis for the valuation process.  The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties.  Accordingly, these estimates are expected to change as future information becomes available.  All of the Company’s proved reserves are located in the State of Texas.

 

Proved oil and natural gas reserve quantities at December 31, 2011 and December 31, 2010, and the related discounted future net cash flows are based on estimates prepared by Corridor Resources, LLC, independent petroleum engineers.

 

Oil reserves

 

   2011
(bbls.)
   2010
(bbls.)
 
         
Beginning balance   6,210    - 
Revisions of previous estimates   -    - 
Purchase of reserves   -    3,490 
Extensions, discoveries and other additions   24,458    3,720 
Sale of reserves        - 
Production   (3,548)   (1,000)
End of year balance   27,120    6,210 

 

41
 

 

The Company performed a series of workover procedures to the wells on the Felix Brandt lease, resulting in an increase in the production capacity of 3,720 bbls over the initial purchase as of December 31, 2010.

 

During 2011, the Company’s primary focus was continuing the enhancement of the acquired wells and drilling new wells. The Company focused development of the James Leonard lease, drilling and completing 3 wells during the spring and summer. With the success of those shallow, low cost projects, the Company focused on acquiring funding for additional wells. On October 14, 2011, the Company entered into a production agreement with BlueRock Energy Capital II, LLC (“BlueRock”). Under the production agreement, BlueRock funded Adino with $410,000 for the drilling of five oil wells on the Company’s Leonard and Felix Brandt leases and for working capital. Under the terms of the production agreement, BlueRock will be entitled to 65% of the net revenue interest of the wells until BlueRock receives $410,000 plus an 18% return on investment. These monies are to be paid as the Company receives production payments on the new wells. After payment of this amount, BlueRock will receive a 3% overriding royalty interest on the wells. As of December 31, 2011, the wells were drilled and completion was underway.

 

 Costs Incurred

 

Capitalized Costs Relating to Oil and Gas Producing Activities

 

   2011   2010 
         
Unproved oil and gas properties  $280,602   $59,060 
Proved oil and gas properties   526,766    223,484 
Total   807,368    282,544 
Accumulated depreciation, depletion, amortization and valuation allowances   (120,741)   (68,205)
End of year balance  $686,627   $214,339 

 

Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development:

Costs incurred in oil and natural gas property acquisition, exploration and development activities are summarized below for the years ended December 31, 2010 and 2011:

 

   2011   2010 
Property acquisition costs:          
Unproved  $-   $59,060 
Proved   -    71,060 
Exploration costs   -    - 
Development costs   485,506    116,603 
Asset retirement cost   3,704    35,821 
Total costs incurred  $489,210   $282,544 

 

Standardized Measure

The standardized measure of discounted future net cash flows relating to the Company’s ownership interests in proved oil reserves for the years ended December 31 are shown below:

 

   2011   2010 
         
Future cash inflows  $2,384,380   $451,160 
Future oil and natural gas operation expenses   (1,157,350)   (327,680)
Future development costs        - 
Future income tax expenses        - 
Future net cash flows   1,227,030    123,480 
10% annual discount for estimating timing of cash flow   (275,760)   (4,890)
Standardized measure of discounted future net cash flow  $951,270   $118,590 

 

42
 

 

 NOTE 28 – SUBSEQUENT EVENTS

 

During the first quarter of 2012, Asher Enterprises, Inc. elected to convert a portion of its outstanding notes receivable with the Company on four separate occasions.  The conversions were made in accordance with the note agreement and resulted in a reduction of the note payable balance of $45,000 and accrued interest of $2,120. Common shares issued in settlement were 9,912,748.

 

On January 6, 2012, one of the Schwartz investors holding a note for $22,500, converted his note into 681 shares of the Company’s Class B Preferred Stock Series 3 shares. Additionally, he invested an additional $30,000 in the Company through the purchase of 857 shares of Class B Preferred Stock Series 3 shares

 

On February 7, 2012 Adino sold all of its membership interest in IFL to Pomisu XXI S.L. (“Buyer”). The purchase price paid by the Buyer was $900,000, paid in two installments with the first installment of $244,824.97 paid on February 7, 2012, and the balance due not later than May 7, 2012. The balance of the purchase price shall be computed as follows: $900,000 minus $244,842.97 (initial installment) minus any IFL liabilities plus any cash on deposit with Regions Bank for the benefit of IFL or cash on deposit with J.P. Morgan Bank for the benefit of the Company. The liabilities assumed included $106,520 in accounts payable, $1,500 to a related party, $110,000 in retained customer deposit and $437,155 for the G J Capital lawsuit judgment.  

 

On February 7, 2012, the Company sold, for $500,000 cash, all oilfield machinery and equipment it had purchased from Ashton Oilfield Services in its November 3, 2011 acquisition. The Company purchased the assets for 100,000 shares of Class B Preferred Stock Series 1, valued at $350,000

 

There were no additional subsequent events through April 16, 2012, the date the financial statements were issued.

 

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

 

There are no disagreements with our accountant on accounting and financial disclosure.

 

ITEM 9A. CONTROL AND PROCEDURES

 

Evaluation of Disclosure Controls and Procedures

 

We carried out an evaluation, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, of the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)).  Based upon that evaluation, our principal executive officer and principal financial officer concluded that, as of the end of the period covered in this report, our disclosure controls and procedures were not effective to ensure that information required to be disclosed in reports filed under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the required time periods and is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

 

Our management, including our principal executive officer and principal financial officer, does not expect that our disclosure controls and procedures or our internal controls will prevent all error or fraud.  A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.  Further, the design of a control system must reflect the fact that there are resource constraints and the benefits of controls must be considered relative to their costs.  Due to the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, have been detected. To address the material weaknesses, we performed additional analysis and other post-closing procedures in an effort to ensure our consolidated financial statements included in this annual report have been prepared in accordance with generally accepted accounting principles. Accordingly, management believes that the financial statements included in this report fairly present in all material respects our financial condition, results of operations and cash flows for the periods presented.

 

43
 

 

Management’s Report on Internal Control Over Financial Reporting

 

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) under the Securities Exchange Act, as amended.  Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2011. In making this assessment, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control-Integrated Framework.  A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company's annual or interim financial statements will not be prevented or detected on a timely basis.  We have identified the following material weaknesses:

 

1.As of December 31, 2011, we did not maintain effective controls over the control environment.  Specifically, the Board of Directors does not currently have any independent members and no director qualifies as an audit committee financial expert as defined in Item 407(d)(5)(ii) of Regulation S-K.  Since these entity level programs have a pervasive effect across the organization, management has determined that these circumstances constitute a material weakness.

 

2.As of December 31, 2011, we did not maintain effective controls over financial statement disclosure.  Specifically, controls were not designed and in place to ensure that all disclosures required were originally addressed in our financial statements.   Accordingly, management has determined that this control deficiency constitutes a material weakness.

 

Because of these material weaknesses, management has concluded that the Company did not maintain effective internal control over financial reporting as of December 31, 2011, based on the criteria established in "Internal Control-Integrated Framework" issued by the COSO.

 

Corrective Action

 

Management plans to address the structure of the Board of Directors and discuss adding an audit committee during 2012.

 

Changes in Internal Control Over Financial Reporting

 

There have been no changes in the Company’s internal control over financial reporting through the date of this report or during the quarter ended December 31, 2011, that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

 

Independent Registered Accountant’s Internal Control Attestation

 

This annual report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting.  On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act, which permanently exempts smaller reporting companies from providing attestation of their internal controls pursuant to Section 404 of the Sarbanes-Oxley Act. As a result, this report does not provide such an attestation, and the Company will be exempt from providing such an attestation until the Company’s market capitalization reaches $75 million.

 

ITEM 9B.   OTHER INFORMATION

 

None.

 

PART III

 

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

 

The directors and officers of the Company as of December 31, 2011, are set forth below. The directors hold office for their respective term and until their successors are duly elected and qualified. The officers serve at the will of the Board of Directors.

 

DIRECTORS, EXECUTIVE OFFICERS, AND SIGNIFICANT EMPLOYEES

Set forth below are the names, ages, and positions of the executive officers and directors of the Company.

 

Name   Age   Office
         
Sonny Wooley   72   Chairman of the Board of Directors
Timothy Byrd   50   Chief Executive Officer and Director
Shannon McAdams, CFA   41   Chief Financial Officer

 

SONNY WOOLEY, CHAIRMAN OF THE BOARD OF DIRECTORS

Mr. Wooley founded Adino in 1989 and managed it as a private company until going public in 1996. He worked with the Company as an outside consultant prior to rejoining it as Chairman in 2001.

 

44
 

 

TIMOTHY G. BYRD, SR., CHIEF EXECUTIVE OFFICER AND DIRECTOR

Mr. Byrd became the Company’s Chief Executive Officer (“CEO”) and director in December 2001. Prior to that time, Mr. Byrd was President of Innovative Capital Markets, an advisory firm that developed growth strategies for corporations through strategic alliances and mergers and acquisitions.

 

SHANNON McADAMS, CHIEF FINANCIAL OFFICER

Effective January 1, 2011, Adino appointed Shannon W. McAdams, CFA, to serve as its Chief Financial Officer (“CFO”). From April through December 2010, Mr. McAdams was retained by Adino as a consultant to assist the Company in developing its exploration and production business, arrange debt financing, and negotiate with vendors. From April 2007 through February 2010, Mr. McAdams was Director at Galway Group, LP, an energy advisory firm specializing in natural gas and renewables. While there, his work focused on financial advisory services and commodity research. From 2005 through 2006, Mr. McAdams was the Director of Origination at Technology Tree Group, Inc., where he was involved in all stages of commercialization of emerging technology companies.

 

We do not have any standing committees.

 

None of our officers or directors have filed any bankruptcy petition, been convicted of or been the subject of any criminal proceedings or the subject of any order, judgment or decree involving the violation of any state or federal securities law within the past ten (10) years.

 

COMPLIANCE WITH SECTION 16(a) OF THE EXCHANGE ACT

Section 16(a) of the Securities Exchange Act of 1934, as amended (the "Exchange Act") requires the Company's officers, directors and persons who own more than 10% of the Company's common stock to file reports of ownership and changes in ownership with the SEC.

 

Officers, directors and greater than 10% stockholders are required by regulation to furnish the Company with copies of all forms they file pursuant to Section 16(a) of the Exchange Act.

 

From our review of the Section 16(a) filings made in connection with the Company’s stock, we determined that a filing was not made with respect to the following transactions:

 

·Our CEO, Timothy G. Byrd, Sr., did not file a Form 4 regarding a grant of 500,000 shares to him on November 24, 2010. The failure to file this form was due to an administrative oversight.
·Our CFO, Shannon McAdams, did not file a Form 3 after his appointment as CFO. Mr. McAdams was unaware of this requirement and will file all applicable Section 16(a) forms promptly.

 

CODE OF ETHICS

The Company has adopted a code of ethics applicable to our CEO, CFO, controller, our other employees, and our suppliers. This code is intended to promote honest and ethical conduct, including the ethical handling of actual or apparent conflicts of interest between personal and professional relationships; full, fair, accurate, timely, and understandable disclosure in reports and documents that we file with, or submit to the SEC and in other public communications that we make; compliance with applicable governmental laws, rules and regulations; the prompt internal reporting of violations of the code to an appropriate person or persons identified in the code; and accountability for adherence to the code. A copy of our code of ethics was filed as an exhibit to our 2008 annual report filed with the SEC.  The Company will provide a copy of our code of ethics, without charge, to any person who requests it. In order to request a copy of our code of ethics, please contact our headquarters and speak with our investor relations department.  Additionally, the complete code of ethics is available on our website at www.adinoenergycorp.com.

 

AUDIT COMMITTEE

The Company does not have an audit committee. The entire Board of Directors instead acts as the Company’s audit committee. Our Board does not have an audit committee financial expert as defined by Securities and Exchange Commission rules due to the small size of the Board. However, the Board is considering an audit committee financial expert in 2012.

 

ITEM 11. EXECUTIVE COMPENSATION

 

The following describes the cash and stock compensation paid to our directors and officers for the two past fiscal years.

 

SUMMARY COMPENSATION TABLE

Name and Principal
Position
  Year   Salary ($)   Bonus   Stock
Awards
   Option Awards
($)
   All Other
Compensation
($)
   Total
($)
 
                             
Timothy G. Byrd, Sr., CEO  2010    180,000    -0-    15,500    -0-    -0-    195,500 
Timothy G. Byrd, Sr., CEO  2011    180,000    -0-    5,500    -0-    -0-    185,500 
                                   
Sonny Wooley, Chairman  2010    180,000    -0-    15,500    -0-    -0-    195,500 
Sonny Wooley, Chairman  2011    180,000    -0-    5,500    -0-    -0-    185,500 
                                   
Shannon W. McAdams, CFO  2010    64,500    -0-    -0-    -0-    -0-    64,500 
Shannon W. McAdams, CFO  2011    146,000    -0-    -0-    -0-    -0-    146,000 
                                   
Nancy Finney, Controller  2010    90,000    -0-    -0-    -0-    -0-    90,000 
Nancy Finney, Controller  2011    90,000    -0-    5,357    -0-    -0-    95,357 
                                    

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Of the amounts reflected above, certain amounts were deferred and not paid as of 12/31/2011:

 

Name  Amount deferred
in 2011
   Amount deferred
in 2010
 
         
Sonny Wooley  $83,500   $76,000 
Timothy Byrd  $77,573   $69,773 
Shannon McAdams  $42,000   $10,500 
Nancy Finney  $19,000   $18,325 

 

Mr. Byrd’s and Mr. Wooley’s salaries are paid in the form of consulting agreements. The Company does not have an employment agreement with Mr. McAdams.

 

DIRECTOR COMPENSATION

 

Name  Year   Fees Earned or
Paid in Cash ($)
  Stock Awards ($)   Total ($)
Peggy Behrens  2010   -0-   15,500(1)  15,500
                 

During November 2010, the Board approved a stock issuance of 500,000 shares each to its three members for services rendered.  The total issuance of 1,500,000 shares resulted in expense to the Company of $46,500, based on the stock’s market price at the date of issuance.  $15,500 of this expense was attributed to Ms. Behrens’ stock issuance. Ms. Behrens resigned as a director in December 2010

OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END

 

There are no outstanding equity awards to management at December 31, 2011.

 

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.

 

EQUITY COMPENSATION PLAN INFORMATION

 

Plan Category  Number of securities to be
issued upon exercise of
outstanding options, warrants
and rights
   Weighted-average exercise
price of outstanding options,
warrants and rights
   Number of securities remaining
available for future issuance
under equity compensation
plans (excluding securities
reflected in column (a))
 
Equity compensation plans approved by security holders   -0-    N/A    -0- 
Equity compensation plans not approved by security holders   500,000   $0.25    -0- 

 

The 500,000 options are issued to our former investor relations firm, SmallCap Support Services, Inc. (“SmallCap”).

 

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The following table shows the ownership of our stock by our directors, officers, and any person we know to be the beneficial owner of more than five percent (5%) of our common stock.

 

Name and Address of Beneficial Owner (1)  Amount and Nature of
Beneficial Ownership (2)
   % of Class 
         
Sonny Wooley   18,857,514(3)   13.92%
           
Timothy G. Byrd, Sr.   18,852,041    13.91%
           
Shannon McAdams, CFA   2,000,000(4)   1.48%
           
Alejandro Perales   8,011,628    5.91%
           
 Executive officers and directors as a group (3 persons)   39,709,555    29.3%

 

The above numbers and percentages are as of April 16, 2012.

 

(1) The address of each beneficial owner is 2500 CityWest Boulevard, Suite 300, Houston, Texas 77042.

(2) Unless otherwise indicated, all shares are held directly with sole voting and investment power.

(3) Includes 256 shares held indirectly.

(4) Mr. McAdams’ shares are held by Vulcan Advisors, LLC, of which Mr. McAdams is the sole equity owner.

 

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.

 

The Company does not have any independent directors. For purposes of determining director independence, we used the standards applicable to companies listed on the NASDAQ Stock Exchange, which are not applicable to us. The Company is considering adding an additional director, who may be independent, in 2012.

 

On March 31, 2011, the Company sold the membership interest of Adino Drilling, LLC to Adino Drilling, Corp. for $600,000. Adino Drilling, Corp. is an entity affiliated with our Chairman, Sonny Wooley. Under the sale agreement, the Company reduced its accrued compensation due to Mr. Wooley by $100,000 and accepted a $500,000 promissory note, bearing interest at 5.24% annually and due in six years.

 

ITEM 14.  PRINCIPAL ACCOUNTANT FEES AND SERVICES

 

AUDIT FEES

We paid $45,300 and $42,500 for the audit of our financial statements and review of our quarterly reports for fiscal year 2011 and 2010, respectively.

 

AUDIT-RELATED FEES

We paid aggregate fees of $-0- for assurance and related services by the principal accountant that are reasonably related to the performance of the audit or review of our financial statements this fiscal year. In 2010, these fees were $-0-.

 

TAX FEES

We paid aggregate fees of $2,600 and $1,750 for tax compliance, tax advice, and tax planning by our principal accountant for the years ended December 31, 2011 and 2010, respectively. These services consisted of preparing and filing our federal income tax and federal excise tax returns.

 

ALL OTHER FEES

We paid aggregate fees of $-0- for products and services provided by our principal accountant not otherwise disclosed above. In 2010, we were billed $-0- for these products and services.

 

PRINCIPAL ACCOUNTANT ENGAGEMENT POLICIES

We do not have an audit committee. We do not have pre-approval policies and procedures for the engagement of our principal accountant. However, the engagement of our principal accountant was approved by our Board of Directors.

 

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PART IV

 

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

 

The following documents are filed as part of this report:

 

Exhibit    
Number   Exhibit
     
3.1   Articles of Incorporation (as amended January 30, 2008) (incorporated by reference to our Form 10-K filed on March 18, 2009)
3.2   Amendment to Articles of Incorporation (amendment for Class B Preferred Stock, Series 1) (incorporated by reference to our Form 8-K filed November 14, 2011 )
3.3   Amendment to Articles of Incorporation (amendment for Class B Preferred Stock, Series 3)
     
3.4   By-laws of Golden Maple Mining and Leaching Company, Inc. (now Adino Energy Corporation) (incorporated by reference to our Form 10-K filed on March 18, 2009)
10.1   Membership Interest Purchase Agreement (incorporated by reference to our Form 10-Q filed on November 22, 2010)
     
10.2   Post-Closing Agreement (incorporated by reference to our Form 10-Q filed on November 22, 2010)
10.3   Resolution of the Board of Directors of February 1, 2010 (incorporated by reference to our Form 10-K filed on April 1, 2011)
10.4   Resolution of the Board of Directors of November 24, 2010 (incorporated by reference to our Form 10-K filed on April 1, 2011)
10.5   BlueRock Energy Capital II Production Agreement
10.6   Asset Purchase Agreement (incorporated by reference to our Form 8-K filed November 14, 2011 )
    Lease with Lone Star Fuel Storage and Transfer, LLC (incorporated by reference to our Form 10-K filed on March 18, 2009)
10.7   Employment Agreement with Sonny Wooley (incorporated by reference to our Form 10-Q filed on August 15, 2011)
10.8   Employment Agreement with Timothy G. Byrd (incorporated by reference to our Form 10-Q filed on August 15, 2011)
10.9   Terminaling Services Agreement for Commingled Products (incorporated by reference to our Form 10-Q filed on November 14, 2011)
10.10   Amendment to Terminaling Agreement (incorporated by reference to our Form 10-Q filed on November 14, 2011)
     
14   Code of Business Conduct and Ethics (incorporated by reference to our Form 10-K filed on March 18, 2009)
21   Subsidiaries of the Registrant
31.1   Certification  of  Chief  Executive  Officer  pursuant  to  Rule 15d-14(a) of the Exchange Act
31.2   Certification of Chief Financial Officer pursuant to Rule 15d-14(a) of the Exchange Act
32.1   Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2   Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

 

101Interactive Data File

 

SIGNATURES

 

Pursuant to the requirements of section 13 or 15(d) of the Securities Exchange Act of 1934, the undersigned has duly caused this Form 10-K to be signed on its behalf by the undersigned, there unto duly authorized, in the City of Houston, Texas on April 16, 2012.

 

ADINO ENERGY CORPORATION  
   
By: /s/ Timothy G. Byrd, Sr.  
Timothy G. Byrd, Sr.  
CEO and Director  

 

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 in the capacities and on the date indicated.

 

Signature   Name and Title   Date
         
/s/ Sonny Wooley   Chairman of the Board   April 16, 2012
Sonny Wooley   of Directors    
         
/s/ Timothy G. Byrd, Sr.   Chief Executive Officer   April 16, 2012
Timothy G. Byrd, Sr.   and Director    
         
/s/ Shannon W. McAdams, CFA   Chief Financial Officer   April 16, 2012
Shannon W. McAdams, CFA        

 

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SUBSIDIARIES OF ADINO ENERGY CORPORATION
     
Name of subsidiary State of incorporation or
organization
Assumed names
     
Intercontinental Fuels, LLC Texas N/A
     
AACM3, LLC Texas Petro 2000
    Exploration
     
PetroGreen Energy, LLC Nevada N/A
     
Adino Exploration, LLC Texas Adino Exploration
    Petro 2000 Exploration Co
     
 Adino Oilfield Services, LLC Texas  

 

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