Attached files

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EX-21 - ADINO ENERGY CORPv217170_ex21.htm
EX-31.1 - ADINO ENERGY CORPv217170_ex31-1.htm
EX-32.1 - ADINO ENERGY CORPv217170_ex32-1.htm
EX-32.2 - ADINO ENERGY CORPv217170_ex32-2.htm
EX-10.8 - ADINO ENERGY CORPv217170_ex10-8.htm
EX-31.2 - ADINO ENERGY CORPv217170_ex31-2.htm
EX-10.7 - ADINO ENERGY CORPv217170_ex10-7.htm
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K

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

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2010

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 March 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 $1,630,151.

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date:  At March 30, 2011, there were 109,123,412 shares of common stock outstanding.

 
 

 

TABLE OF CONTENTS
 
   
Page
No.
PART I
Item 1.
Business
3
Item 2.
Properties
7
Item 3.
Legal Proceedings
7
     
PART II
     
Item 5
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
8
Item 6
Selected Financial Data
10
Item 7
Management’s Discussion and Analysis of Financial Condition and Results of Operations
10
Item 7A
Quantitative and Qualitative Disclosures About Market Risk
14
Item 8
Financial Statements and Supplementary Data
15
 
Report of Independent Registered Public Accounting Firm
15
 
Consolidated Balance Sheets – December 31, 2010 and December 31, 2009
16
 
Consolidated Statements of Operations- Years Ended December 31, 2010 and 2009
17
 
Consolidated Statement of Changes in Stockholders’ Deficit – Years Ended December 31, 2010 and 2009
18
 
Consolidated Statements of Cash Flows- Years Ended December 31, 2010 and 2009
19
 
Notes to Consolidated Financial Statements
20
     
Item 9
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
38
Item 9A
Controls and Procedures
38
Item 9B
Other Information
39
     
PART III
     
Item 10
Directors, Executive Officers and Corporate Governance
39
Item 11
Executive Compensation
40
Item 12
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
41
Item 13
Certain Relationships and Related Transactions, and Director Independence
42
Item 14
Principal Accounting Fees and Services
42
     
PART IV
     
Item 15
Exhibits, Financial Statement Schedules
42
     
Signatures
 
43

 
2

 
 
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 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. We now own 100% of IFL.

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.

DESCRIPTION OF BUSINESS

Oil and Gas Exploration and Production

As of 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 is a licensed Texas oilfield operator currently operating 11 wells on two leases covering approximately 300 acres in Coleman County, Texas. Petro 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 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 plans a waterflood project, which management believes will substantially increase both daily production and economically recoverable reserves.

Since the acquisition, the Company has completed Phase I of its workover program on its Felix Brandt and Felix Brandt "A" 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 Brandt Leases, including retention berms around the tank batteries, trenching flow-lines and removal of debris from the area.

 
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In December 2010, the Company began drilling on the James Leonard lease in southeast Coleman County, Texas. The primary target pay zone is the Fry Sand at approximately 1,200 feet. Adino owns 100% of the working interest (87.5% net revenue interest) in the James Leonard lease.  Drilling was still in progress at December 31, 2010.

The Company believes that this line of business will be promising and the Company plans to actively pursue future opportunities in the oil and gas exploration business.

Fuel Storage Operations

The Company’s wholly-owned subsidiary, IFL, continues to lease the terminal at 17617 Aldine Westfield Road, Houston, Texas from Lone Star Fuel Storage and Transport, LLC (“Lone Star”).  Utilizing a fuel storage and throughput model, revenues continue to remain strong. During fiscal year 2010, IFL provided 94.6% of the Company’s revenues.

GOVERNMENTAL REGULATIONS / ENVIRONMENTAL MATTERS

Oil and Gas Exploration and Production

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 natural gas 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.

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 (“NORM”) 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.

Fuel Storage Operations

Our operations are 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.

 
4

 

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 ("NORM"). 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.

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, 2010, Adino and its subsidiaries have four employees. We have consulting and management arrangements with our officers and have outsourced our fuel terminaling operations to minimize payroll expense. We have contracts with 8 persons, including executive officers, non-executive officers, secretarial and field personnel.

COMPETITION

Oil and Gas Exploration and Production

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.

 
5

 

Fuel Storage Operations
The market for fuel storage is localized by its nature. Fuel wholesalers need quick and close access to fuel to supply their customers. As a result, the relevant market may not be a city, but only a certain part of a city.

Adino’s IFL terminal is located in North Houston close to the George Bush Intercontinental Airport. Due to the size of the Houston metropolitan area, the relevant market is North Houston, not the entire metropolitan area.

There are several terminals in the Houston area. Several of these terminals are owned by integrated petroleum companies and exist solely to supply their franchisees and company-owned retail locations. Others sell to wholesalers in general but will not sell to competitors.

Overall, we believe that competition to IFL is negligible given its location and the fact that it serves independent petroleum wholesalers.

FUTURE BUSINESS

Oil and Gas Exploration and Production

During 2010, the Company purchased PetroGreen Energy, LLC and AACM3, LLC, jump-starting its re-entry into the oil and gas exploration and production industry.  To facilitate those operations, the Company started two new wholly owned subsidiaries, Adino Exploration, LLC and Adino Drilling, LLC.

Adino Exploration is a licensed Texas oilfield operator currently operating 11 wells on two leases covering approximately 300 acres in Coleman County, Texas. Adino Drilling operates a drilling rig, two service rigs, and oilfield service & support equipment.  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 plans a waterflood project, which management believes will substantially increase both daily production and economically recoverable reserves.

Since the acquisition, the Company has completed Phase I of its workover program on its Felix Brandt and Felix Brandt "A" 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 Brandt Leases, including retention berms around the tank batteries, trenching flow-lines and removal of debris from the area.

In December 2010, the Company began drilling on the James Leonard lease in southeast Coleman County, Texas. The primary target pay zone is the Fry Sand at approximately 1,200 feet. Adino owns 100% of the working interest (87.5% net revenue interest) in the James Leonard lease.  Drilling was still in progress at December 31, 2010.

The Company believes that this line of business will be promising and the Company plans to actively pursue future opportunities in the oil and gas exploration business.

Fuel Storage Operations

The Company will continue to focus on identifying and purchasing or operating under-performing or non-performing terminal assets.  With the success of the IFL terminal, Adino has proven its expertise and proficiency at taking terminal assets, re-permitting and re-licensing the facilities, installing technologically advanced equipment and outsourcing everyday operations.  This approach allows us to concentrate on bringing on customers and revenues, producing positive cash flow and property value enhancement.

At the current facility, IFL is focusing on the wholesale diesel market and subsequently intends to expand into gasoline.  As more wholesalers (jobbers) are delivering from rack to customer, the location and availability of product is very important to overall profitability.  IFL negates the need for distributors in North Houston to store fuel.  Consequently, they concentrate on just-in-time deliveries to their customers and therefore minimize their overall transportation costs.

 
6

 

IFL also intends to become a merchant fuel supplier to specifically provide fuel inventories to its existing customer base.  This will complete the value-added service strategy to our customers as laid out in the Company’s mission statement.  Management believes this will significantly enhance the revenues and profits of each terminal. During fiscal year 2010, we entered into a memorandum of understanding with Saranac Energy International, Inc. (“Saranac”), and Sunco Group, LLC (“Sunco”), whereby Saranac and Sunco would provide Adino with an inventory line of credit and other financing in order to help Adino enter the fuel merchant business. As of the date of this report, however, Saranac and Sunco had not yet provided this financing.

The Company is also poised to capture the growing alternative fuels and biodiesel market using its present distribution and blending infrastructure. Biodiesel is a domestic, renewable fuel for diesel engines derived from natural oils like soybean oil. Biodiesel can be used in any concentration with petroleum based diesel fuel in existing diesel engines with little or no modification, and is produced (refined) by a chemical process that removes glycerin from the oil.

ITEM 2. DESCRIPTION OF PROPERTY

Adino Corporate

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 and Adino Drilling, LLC have 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. Gasoline and diesel fuel are shipped out by tanker truck. However, IFL is not currently pursuing the aviation market.

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.

ITEM 3. LEGAL PROCEEDINGS

Adino Energy Corporation v. Coastal Resources Group, Inc., et. al.

On December 17, 2007, the Company filed suit against Coastal Resources Group, Inc. (“Coastal”) in the 12th Judicial District Court of Walker County, Texas, under Cause No. 24102, to collect a $30,000 loan made to Coastal in 2004. Adino’s suit seeks $30,000 plus interest at 6% per annum, plus attorney’s fees and costs of court.

A trial date was originally set for July 2009 but was later passed. A new trial date has not been set.

 
7

 

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 its wholly-owned subsidiary, Intercontinental Fuels, LLC (“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 alleges 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 has also alleged fraudulent conduct by one or more of the defendants.

Adino, IFL, and Mr. Byrd and Mr. Wooley have 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, and Mr. Byrd and Mr. Wooley contend 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.

The court has granted a partial summary judgment to G J Capital against IFL ruling that IFL received the money in question and did not repay it, with the amount of damages to be determined at a later date.

Both Adino and IFL are vigorously defending this suit and the Company has provided Mr. Byrd and Mr. Wooley with a legal defense since the Company determined they were sued in their capacity as directors and officers of Adino.

This case is currently set for trial in April 2011; however, the case is likely to be continued to a later date.  The Company maintains the original contract amount of $275,000 as a liability, but believes it will prevail in the suit.

 PART II

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

As of December 31, 2010, Adino had 107,260,579 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 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  
                 
Fourth Quarter 2009
  $ 0.03     $ 0.01  
Third Quarter 2009
  $ 0.02     $ 0.01  
Second Quarter 2009
  $ 0.03     $ 0.02  
First Quarter 2009
  $ 0.04     $ 0.01  

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

DIVIDENDS

We have not paid any dividends on our common 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.

 
8

 

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

RECENT SALES OF UNREGISTERED SECURITIES

In May 2008, the Company issued 750,000 shares to its former legal counsel and 1,000,000 shares to its former accountant for services rendered, resulting in an additional expense of $15,070, based upon the stock’s market price at issuance.

In July and September 2008, the Company settled outstanding payables for legal and consulting expenses. The Company issued 653,847 shares of restricted stock in settlement of $26,600.  As consideration for converting the amount to restricted stock, the Company offered the common shares to the vendor at a 30% discount to the closing price on the conversion date, resulting in an additional expense of $9,007 to the Company, based upon the stock’s market price at issuance.

Additionally, in July 2008, the Company settled a demand note in the principal amount of $23,000, issuing 597,403 shares of restricted stock.   As consideration for converting the amount to restricted stock, the Company offered the common shares to the note holder at a 30% discount to the closing price on the conversion date, resulting in an additional expense of $9,857 to the Company, based upon the stock’s market price at issuance.

On August 1, 2008, the Company settled a portion of the outstanding accrued salary for both Mr. Byrd and Mr. Wooley.  Mr. Byrd and Mr. Wooley elected to convert $200,000 and $130,472 of the compensation due to them, respectively, into restricted stock.  As consideration for converting these amounts into restricted stock, the Company offered the common shares at a 30% discount to the closing bid price on the conversion date. Mr. Byrd and Mr. Wooley were issued 5,102,041 and 3,328,367 shares respectively, resulting in an additional expense of $259,657 to the Company, based on the stock’s market price at issuance.

On September 29, 2008, we issued a warrant to Lone Star whereby Lone Star can acquire 1,500,000 shares of Adino for $0.04 per share.  The warrant also allows Lone Star to purchase these shares on a “cashless” basis.

In October 2008, the Company settled outstanding payables for legal and consulting expenses.  The Company issued 669,401 shares of restricted stock in settlement of $14,526 outstanding.

On October 22, 2008, the Company settled a portion of the outstanding accrued salary for both Mr. Byrd and Mr. Wooley.  Mr. Byrd and Mr. Wooley each elected to convert $50,000 of the compensation due to them into restricted stock.  Mr. Byrd and Mr. Wooley were issued 2,304,147 shares each in settlement of this amount.

On February 20, 2009, the Company authorized the issuance of 1,500,000 shares each to Mr. Byrd and Mr. Wooley and 500,000 shares to Ms. Behrens. This issuance resulted in an expense to the Company of $52,500 based on the fair market value of the shares at the issuance date.

On March 20, 2009, the Board approved a stock issuance of 1,000,000 shares of restricted common stock to Stuart Sundlun for consulting services.  This issuance resulted in an expense to the Company of $19,000, based on the fair market value of the shares at the issuance date.

In May 2009, the Company settled the lawsuit against CapNet Securities Corporation and related entities.  The settlement called for issuance of 4,500,000 shares of restricted stock to CapNet Securities Corporation and 1,000,000 shares of restricted stock to be issued to CapNet Risk Management, Inc. The settlement and stock issuance resulted in a gain to the Company of $7,896.

On February 1, 2010, the Company approved a retention bonus of 250,000 shares of common stock for the president of Intercontinental Fuels, LLC and the president of the terminal management company used by IFL.  The issuance resulted in expense to the Company of $5,700, based on the fair market value of the shares at the issuance date.

As of July 1, 2010, the Company acquired PetroGreen Energy LLC and AACM3, LLC d/b/a Petro 2000 Exploration Co. (together "Petro Energy"). Adino 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 the assets held by Petro Energy for $1.00 on July 1, 2010.  The assets contemplated by this “clawback” agreement were valued at $551,621 on July 1, 2010.

On September 7, 2010, the Company awarded Vulcan Advisors, LLC 2,000,000 shares of stock for consulting services performed in conjunction with financing acquired for the Company’s recent oil and gas exploration opportunities.  This issuance resulted in an expense to the Company of $70,000.  Vulcan Advisors, LLC is owned by Shannon W. McAdams, CFA.  During 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. On January 1, 2010, Mr. McAdams was named Chief Financial Officer of Adino.
 
During November 2010, the Company awarded 500,000 shares of stock to each of its three directors as compensation.  The issuance resulted in expense to the Company of $46,500, based on the fair market value of the shares at the issuance date.
 
9

 
 
Each of these offerings were made upon reliance on the exemption from registration contained in Section 4(2) of the Securities Act.

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, PetroGreen Energy LLC, and AACM3, LLC.  All intercompany accounts and transactions have been eliminated.

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.

 
10

 

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.

Based on the evaluations performed by management, there were no indicators of impairment at December 31, 2010 or 2009.

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 17 for further information related to the Company’s accounting for uncertainty in income taxes.

RESULTS OF OPERATIONS

Revenue: The Company’s revenues were $2,002,773 and $2,186,536 for the years ended December 31, 2010 and 2009, respectively. The Company’s main revenue source was its wholly owned subsidiary, IFL.  IFL added two new customers in 2009, accounting for the increased terminal revenue in the latter part of 2009 and early 2010.  In May 2010, IFL management negotiated a long term contract with a regional fuel supplier to be the primary customer of the Houston terminal. The new arrangement allows for consistent revenues over the long term and does not include revenues for fuel additives, thus decreasing revenue since the May 2010 contract signing.

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 begun contributed $58,107 in revenue during the last 6 months of 2010.  There are no comparable revenues for 2009.

Cost of Product Sales:  As customers take their fuel from the IFL terminal, certain fuel additives must be mixed with the diesel to comply with state and federal regulations.  In order to decrease product cost volatility and improve operational efficiency, IFL contracted with a third party fuel additive provider for all fuel additives through April 2010.  The new Houston terminal customer contract begun in May 2010 does not require that IFL provide additive services. Therefore, the Company realized a decrease in product sales expense of $308,265 or 55%, for 2010. Total expense for the year ended December 31, 2010 was $248,717, compared to the full year expense of $556,982 for 2009.

Payroll and Related Expenses:  With the addition of Adino Exploration, the Company has hired several employees to operate the leases owned by the Company.  Additionally, the Company has added payroll for one employee at its corporate office. These employee additions result in payroll expense of $90,213 for the year ended December 31, 2010. There is no expense for the similar reporting periods in 2009.

Terminal Management:  The Company has outsourced its terminal operations since July 2007.  The monthly contract includes employee salaries and benefits, terminal operational expenses, minor repairs, maintenance, insurance and other ancillary operating expenses.  Terminal management expense at December 31, 2010 was $400,360, relatively consistent with the expense incurred in 2009 of $400,980.  Management is encouraged by the success of this alliance and plans to utilize the terminal management model in any future terminal acquisitions.

 
12

 

General and Administrative: The Company’s expenses for the year ended December 31, 2010 and 2009 were $685,334 and $584,192, respectively, an increase of 18%. General and administrative expense is primarily rent expense paid on the IFL terminal to Lone Star, currently $31,855 per month, or $382,260 for 2010, consistent with 2009 expense.  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, $17,193 in insurance expenses, and $19,348 in additional travel expense. Although property taxes were reduced by $3,272 for 2010, tax expenses increased 27% from $83,994 in 2009 to $106,532 in 2010, primarily due to severance taxes paid on the oil revenues and an IRS settlement.  The Company incurred $30,000 in bad debt expense in September 2010 and had increased filing fees of $7,742 resulting from increased press releases and SEC filings related to the PetroGreen Energy acquisition in July, 2010.
Legal and Professional:  Legal and professional expense was $281,623 and $182,463 for the year ended December 31, 2010 and 2009, respectively. Legal fees increased from $45,879 in 2009 to $147,019 in 2010, an increase of $101,140, primarily due to increased expense related to the Petro Energy acquisition and the lawsuit involving G J Capital. 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 $785,433 and $722,739 for the years ended December 31, 2010 and 2009, respectively, an increase of $62,594 or 9%.  In the second quarter of 2010, IFL contracted with two consultants to formalize the Company’s business plan and marketing presentation package, resulting in additional expense of approximately $51,000. The consultants were retained through August to continue this effort. One of the consultants remained with the Company to assist with Petro Energy’s workover and waterflood projects and became an employee of the Company in October 2010. Additionally, the Company awarded 2,000,000 shares of stock to a consulting group for assisting in a financing project, resulting in a $70,000 expense to the Company. The Company awarded stock compensation to its Board of Directors for service provided during 2010 resulting in an expense of $46,500.  During 2009, the Company saw unusual expenses primarily due to a common stock award granted to the Board of Directors of $52,500 and additional compensation of $148,907 granted to the officers and controller of the Company.

Depreciation Expense: Depreciation expense was $62,277 and $12,172 for the years ended December 31, 2010 and 2009, respectively.  With the acquisition of PetroGreen Energy, the Company added significant oil and gas machinery and equipment as of July 1, 2010 resulting in $30,141 in additional expense.  Additionally, current oil production from the Felix Brandt lease resulted in $20,569 in depletion.  See Notes 4 and 8 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.

Operating Supplies: Supplies expense was $24,949 and $7,270 for the years ended December 31, 2010 and 2009, respectively. The Company did not have significant operating supplies expense in 2010 prior to the Petro Energy acquisition. During the last six months of 2010, the Company incurred supplies expense related to its oil lease workover and waterflood projects in Coleman, Texas.

Interest Income:  Interest income remained consistent at $67,667 and $64,876 for the years ended December 31, 2010 and 2009, respectively. The Company has agreed to an amendment on the $750,000 note receivable with Mr. Sundlun.  This amendment extends 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, accounting for the consistent expense.

Interest Expense:  Interest expense was $181,097 and $165,591 for the years ended December 31, 2010 and 2009, respectively. During the third quarter of 2010, the Company closed two separate financings, each resulting in 8% annual interest to the Company, resulting in additional interest expense of $20,802. Interest expense consistent between 2009 and 2010 are for the notes to Mr. Sundlun and vehicle financing. See Note 11 of the Company’s financial statements for additional information regarding interest expense

Gain from Extinguishment of Debt:  The Company settled a large payable with an IFL vendor in October 2010 resulting in a gain to the Company of $65,000.

Gain from Lawsuit / Sale Leaseback:  The lawsuit settlement on March 23, 2007 resulted in a gain to the Company of $1,480,383.  The transaction was deemed to be a sale/leaseback, and therefore the gain was recognized over the life of the capitalized asset, 15 years.

On September 30, 2008, the Company assigned its rights to purchase the IFL terminal to Lone Star.  As of this date, the unamortized gain from lawsuit was $1,332,345.  The Company’s transaction with Lone Star resulted in an additional gain of $624,047.  These amounts, totaling $1,956,392, will be amortized over the 60 month life of the Lone Star operating lease.  See Note 3 above for more information regarding these transactions.

 
13

 

Additionally in 2009, the Company settled a lawsuit with CapNet Securities, Corp.  The settlement resulted in a gain to the Company of $15,022.

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, 2010 for a loss of $67,673. See Note 13 of the Company’s financial statements for a more thorough discussion of this loss. There is no gain or loss for the similar reporting periods in 2009.

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 July 1, 2010 at $408,760 and was revalued at year end at $337,354, resulting in a gain on change in clawback valuation of $71,406 for the year ended December 31, 2010.

Other Income:  Other income for the year ended December 31, 2010 was $25,418.  During the 4th quarter 2010, the Company entered into a memorandum of understanding on a financing opportunity.  The transaction required the potential lending party to pay the Company a non-refundable deposit of $25,000.  The financing was not completed and the deposit was retained by the Company, as agreed.  There was no other income for 2009.

Net Income/Loss: The Company had net loss of $277,802 and net income of $23,029 for the years ended December 31, 2010 and 2009, respectively. This increased loss was primarily due to expenses incurred for operating supplies, legal expense, consultants and payroll and depreciation associated with the acquisition of Petro Energy. The current loss was partially offset by a non-operating gain on change in fair value of clawback provision of $71,406 and recognition of the deferred gain on lawsuit / sale leaseback of $416,696.

Cash:  The Company’s cash balance at December 31, 2010 of $285,171 is considerably lower than the balance at December 31, 2009 of $502,542.  The decrease is primarily due to the acquisition and ongoing operations of the oil and gas exploration and drilling companies, discussed in Item 1.

LIQUIDITY AND CAPITAL RESOURCES

During the years 2003 to 2006, Adino had substantial liquidity and cash flow problems due to its lack of operating revenues. From 2007 through 2010, the Company’s liquidity and cash flow improved due to revenues generated by IFL; however, we still experienced liquidity problems due to debts incurred by Adino and IFL in prior years.

The Company’s access to financing improved somewhat during 2010, however, as a result of several convertible notes that we issued to two groups of private investors. As a result of these private note issuances, the Company raised $457,500. 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.

Nonetheless, at December 31, 2010, the Company’s cash available was approximately half of what it was as of December 31, 2009. This is due to the increased operating expenses as a result of the Petro Energy acquisition, increased personnel costs, and higher legal and consulting expenses as a result of the G J Capital lawsuit. In addition, the Company's available cash at December 31, 2009 was higher than normal due to a new contract entering into effect with an IFL customer toward the end of the year.

As of December 31, 2010, the Company has a working capital deficit of $3,712,062 and total stockholders’ deficit of $2,503,370.  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, 2010, there are several non-cash items:  $391,272 is a non-cash deferred gain on the terminal transaction, $337,354 is due to a non-cash clawback provision and $102,511 is attributed to a derivative liability.  Additionally, $909,960 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.

 
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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, 2010 and 2009 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, 2010 and 2009 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
March 31, 2011

 
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ADINO ENERGY CORPORATION
Consolidated Balance Sheets
AS OF DECEMBER 31, 2010 AND 2009

   
December 31, 2010
   
December 31, 2009
 
             
ASSETS
           
Cash in bank
  $ 285,171     $ 502,542  
Accounts receivable, net of allowances
    9,615       96,734  
Deposits and prepaid assets
    58,062       255  
Notes receivable, net of unamortized discount of $46,570
    703,430       -  
Interest receivable
    375,208       -  
Total current assets
    1,431,486       599,531  
                 
Fixed assets, net of accumulated depreciation of $69,052 and $28,366, respectively
    520,063       32,659  
Oil and gas properties (full cost method), net of accumulated amortization, depreciation, depletion, and asset impairment
               
Proved properties
    155,279       -  
Unproved properties
    59,060       -  
Note receivable, net of unamortized discount of $114,138
    -       635,862  
Goodwill
    1,566,379       1,559,240  
Other assets
    6,500       375,208  
Total non-current assets
    2,307,281       2,602,969  
TOTAL ASSETS
  $ 3,738,767     $ 3,202,500  
                 
LIABILITIES AND SHAREHOLDERS’ DEFICIT
               
Accounts payable
  $ 457,987     $ 511,747  
Accounts payable - related party
    47,612       42,871  
Accrued liabilities
    371,601       330,568  
Accrued liabilities - related party
    909,960       1,023,687  
Contract clawback provision
    337,354       -  
Notes payable - current portion
    1,864,251       291,618  
Interest payable
    660,000       510,000  
Derivative liability
    103,511       -  
Deferred gain - current portion
    391,272       391,272  
Total current liabilities
    5,143,548       3,101,763  
                 
Deferred gain, net of current portion
    684,744       1,076,022  
Notes payable, net of current portion
    413,845       1,522,483  
TOTAL LIABILITIES
    6,242,137       5,700,268  
                 
SHAREHOLDERS’ DEFICIT
               
Preferred stock, $0.001 par value, 20,000 shares authorized, no shares issued and outstanding
    -       -  
Capital stock, $0.001 par value, 500 million shares authorized, 107,260,579 and 93,260,579 shares issued and outstanding at December 31, 2010 and December 31, 2009, respectively
    107,260       93,260  
Additional paid in capital
    13,785,442       13,527,242  
Retained deficit
    (16,396,072 )     (16,118,270 )
Total shareholders’ deficit
    (2,503,370 )     (2,497,768 )
                 
TOTAL LIABILITIES AND SHAREHOLDERS’ DEFICIT
  $ 3,738,767     $ 3,202,500  

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

 
16

 

ADINO ENERGY CORPORATION
Consolidated Statements of Operations
FOR THE YEARS ENDED DECEMBER 31, 2010 AND 2009

   
December 31,
   
December 31,
 
   
2010
   
2009
 
             
REVENUES
           
Terminal operations
  $ 1,944,666     $ 2,186,536  
Oil and gas operations
    58,107       -  
Total revenues
    2,002,773       2,186,536  
                 
OPERATING EXPENSES
               
Cost of product sales
    248,717       556,982  
Payroll and related expenses
    90,213       -  
Terminal management
    400,360       400,980  
General and administrative
    685,334       584,192  
Legal and professional
    281,623       182,463  
Consulting fees
    785,433       722,739  
Repairs
    26,187       1,073  
Depreciation expense
    62,277       12,172  
Impairment expense
    47,481       -  
Operating supplies
    24,949       7,270  
Total operating expenses
    2,652,574       2,467,871  
                 
OPERATING LOSS
    (649,801 )     (281,335 )
                 
OTHER INCOME AND EXPENSES
               
Interest income
    67,667       64,876  
Interest expense
    (181,097 )     (165,591 )
Gain on extinguishment of debt
    65,000       -  
Gain from lawsuit / sale leaseback
    391,278       405,079  
Loss on derivative
    (67,673 )     -  
Gain on change in fair value of clawback provision
    71,406       -  
Other income (expense)
    25,418       -  
Total other income and expense
    371,999       304,364  
                 
NET INCOME (LOSS)
  $ (277,802 )   $ 23,029  
                 
Net income (loss) per share, basic and fully diluted
  $ (0.00 )   $ 0.00  
                 
Weighted average shares outstanding, basic and fully diluted
    99,512,634       90,731,812  

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

 
17

 

ADINO ENERGY CORPORATION
Consolidated Statement of Changes in Shareholders’ Deficit
FOR THE YEARS ENDED DECEMBER 31, 2009 and 2010

   
Shares
   
Amount
   
Additional
Paid in
Capital
   
Retained
Deficit
   
Total
 
Balance December 31, 2008
    83,260,579     $ 83,260     $ 13,306,247     $ (16,141,299 )   $ (2,751,792 )
                                         
Options issued for services
    -       -       21,995       -       21,995  
Shares issued for services - officers
    3,500,000       3,500       49,000       -       52,500  
Shares issued for services
    1,000,000       1,000       18,000       -       19,000  
Shares issued in lawsuit settlement
    5,500,000       5,500       132,000       -       137,500  
Net income
    -       -       -       23,029       23,029  
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 services
    2,500,000       2,500       68,000               70,500  
Shares issued for acquisition
    10,000,000       10,000       140,000               150,000  
Net loss
                            (277,802 )     (277,802 )
Balance December 31, 2010
    107,260,579     $ 107,260     $ 13,785,442     $ (16,396,072 )   $ (2,503,370 )

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

 
18

 

ADINO ENERGY CORPORATION
Consolidated Statements of Cash Flows
FOR THE YEARS ENDED DECEMBER 31, 2010 AND 2009

   
December 31,
2010
   
December 31,
2009
 
             
CASH FLOWS FROM OPERATING ACTIVITIES:
           
Net income (loss)
  $ (277,802 )   $ 23,029  
                 
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
               
Depreciation and depletion
    61,410       12,172  
Accretion
    868       -  
Amortization of discount on note receivable
    (67,568 )     (54,643 )
Options issued for services
    -       21,995  
Stock based compensation
    -       52,500  
Shares issued for services
    122,200       19,000  
Bad debt expense
    30,000       -  
Gain on asset disposal
    -       (2,205 )
Gain from lawsuit / sale amortization
    (391,278 )     (399,175 )
Gain on debt forgiveness
    (65,000 )     -  
Loss on derivative
    67,673       -  
Gain on change in fair value of clawback provision
    (71,406 )     -  
Oil and gas impairment
    47,481       -  
Amortization of debt discount
    9,031       -  
Changes in operating assets and liabilities:
               
Accounts receivable
    57,116       (15,262 )
Other assets
    (14,306 )     5,447  
Accounts payable and accrued liabilities
    56,599       501,781  
Lease obligation
            -  
Net cash provided by (used in) operating activities
    (434,982 )     164,639  
                 
CASH FLOWS FROM INVESTING ACTIVITIES:
               
Purchase of equipment
    (223,191 )     (10,264 )
Principal payments on note receivable
    -       325,971  
Net cash provided by (used in) investing activities
    (223,191 )     315,707  
                 
CASH FLOWS FROM FINANCING ACTIVITIES:
               
Borrowings on note payable
    457,500       -  
Principal payments on note payable
    (16,698 )     (8,032 )
Net cash provided by (used in) financing activities
    440,802       (8,032 )
                 
Net change in cash and cash equivalents
    (217,371 )     472,314  
Cash and cash equivalents, beginning of period
    502,542       30,228  
Cash and cash equivalents, end of period
  $ 285,171     $ 502,542  
                 
Cash paid for:
               
Interest
  $ 12,285     $ 12,378  
Income taxes
  $ -     $ -  
Supplemental disclosures of non-cash information:
               
Contract clawback provision
  $ 408,760     $ -  
Acquisition purchased with stock
  $ 150,000     $ -  
Asset retirement obligation
  $ 36,255     $ -  
Note discount
  $ 35,838     $ -  
Operating license deposit
  $ 50,000     $ -  

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

 
19

 

ADINO ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 - ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Background

Adino Energy Corporation ("Adino" or the "Company"), 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 an energy company.

The Company has a subsidiary, Intercontinental Fuels, LLC (“IFL”), a Texas limited liability company, which was founded in 2003. Adino first acquired 75% of IFL’s membership interests in 2003 and now owns 100% of IFL.

In January 2008, at the annual shareholder’s meeting, the Company changed its name to Adino Energy Corporation.

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

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.

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, 2010 and 2009, we had no reserve for doubtful accounts as all of our receivables were collected early in the subsequent year or 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.

 
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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, 2010 or December 31, 2009.

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.

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 the discount method.

 
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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.  As described above, in accordance with the requirements of Staff Accounting Bulletin 104, 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) 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.

Segment Reporting

The Company is required to present segment reporting in the annual report when a reportable segment meets one or more of the following tests: (1) revenue is 10% or more of combined revenue; (2) operating profit is 10% or more of combined operating profit (operating profit excludes unallocable general corporate revenue and expenses, interest expense, and income taxes); or (3) identifiable assets are 10% or more of the combined identifiable assets; also called line of business reporting. Current guidance requires that financial statements include information about operations in different industries, foreign operations, export sales, major customers, and government contracts. The disclosures provide data useful in evaluating a segment's profit potential and riskiness. A significant segment in the past that is expected to be so again should be reported even though it failed the 10% test in the current year. Segments shall represent a substantial portion (at least 75%) of the company's total revenue to unaffiliated customers. As a matter of practicality, however, no more than 10 segments should be shown. While intersegment sales or transfers are eliminated in consolidated financial statements, they are included for purposes of segment disclosure in determining the 10% and 75% rules. The Disclosures are not required for an enterprise that derives 90% or more of its revenues from one industry. The segmental disclosures may be presented in the body of the financial statements, footnotes, or a separate schedule. The disclosure requirements are not applicable to nonpublic companies or in interim reports.
 
With the acquisition of the oil and gas companies discussed in Item 1, the Company had a segment that represented in excess of 10% of identifiable assets.  See Note 22 for segment reporting detail.
 
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 17 for further information related to the Company’s accounting for uncertainty in income taxes.

Income (Loss) Per Share

Current guidance requires earnings per share 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.   Basic and diluted EPS are the same as the effect of our potential common stock equivalents would be anti-dilutive.

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.

 
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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.

The Company has granted options and warrants to purchase Adino’s common stock.  These instruments have been valued using the Black-Scholes model and are fully detailed in Note 15.

 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, 2010 and 2009, Adino evaluated and determined that no impairment was warranted on the assets of Adino Energy Corporation or its subsidiary, Intercontinental Fuels, LLC.  See Note 8 for discussion of the impairment of Adino Exploration, LLC’s oil and gas assets as of December 31, 2010.

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.

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.

Based on the evaluations performed by management, there were no indicators of impairment at December 31, 2010 or 2009.

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.
 
23

 
 
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.

See Note 6 for additional discussion.

Reclassification
 
Certain amounts reported in the prior period financial statements have been reclassified to the current period presentation.
 
Recently Issued Accounting Pronouncements
 
On January 1, 2009, the Company adopted a new accounting standard issued by the FASB related to accounting for business combinations using the acquisition method of accounting (previously referred to as the purchase method). Among the significant changes, this standard requires a redefining of the measurement date of a business combination, expensing direct transaction costs as incurred, capitalizing in-process research and development costs as an intangible asset and recording a liability for contingent consideration at the measurement date with subsequent re-measurements recorded in the results of operations. This standard also requires costs for business restructuring and exit activities related to the acquired company to be included in the post-combination financial results of operations and also provides new guidance for the recognition and measurement of contingent assets and liabilities in a business combination. In addition, this standard requires several new disclosures, including the reasons for the business combination, the factors that contribute to the recognition of goodwill, the amount of acquisition related third-party expenses incurred, the nature and amount of contingent consideration, and a discussion of pre-existing relationships between the parties. The application of this standard did not affect the Company during 2009.

On January 1, 2009, the Company adopted a new accounting standard issued by the FASB that establishes accounting and reporting standards for noncontrolling interests in a subsidiary in consolidated financial statements, including deconsolidation of a subsidiary. This standard requires entities to record the acquisition of noncontrolling interests in subsidiaries initially at fair value. The adoption of this standard did not impact earnings per share attributable to Adino Energy Corporation’s common stockholders as there were no changes in the Company’s ownership interests in subsidiaries or deconsolidation of subsidiaries for the year ended December 31, 2010.

On January 1, 2009, the Company adopted a new accounting standard issued by the FASB related to the disclosure of derivative instruments and hedging activities. This standard expanded the disclosure requirements about an entity’s derivative financial instruments and hedging activities, including qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of and gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative instruments.

Effective June 30, 2009, the Company adopted a newly issued accounting standard related to accounting for and disclosure of subsequent events in its consolidated financial statements. This standard provides the authoritative guidance for subsequent events that was previously addressed only in United States auditing standards. This standard establishes general accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued and requires the Company to disclose the date through which it has evaluated subsequent events and whether that was the date the financial statements were issued or available to be issued. This standard does not apply to subsequent events or transactions that are within the scope of other applicable GAAP that provide different guidance on the accounting treatment for subsequent events or transactions. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements.

 
24

 

In June 2009, the FASB issued an amendment to the accounting standards related to the consolidation of variable interest entities (“VIE”). This standard provides a new approach for determining which entity should consolidate a VIE, how and when to reconsider the consolidation or deconsolidation of a VIE and requires disclosures about an entity’s significant judgments and assumptions used in its decision to consolidate or not consolidate a VIE. Under this standard, the new consolidation model is a more qualitative assessment of power and economics that considers which entity has the power to direct the activities that “most significantly impact” the VIE’s  economic performance and has the obligation to absorb losses or the right to receive benefits that could be potentially significant to the VIE. This standard is effective for the Company as of January 1, 2010 and the Company does not expect the impact of its adoption to be material to its consolidated financial statements.

In October 2009, the FASB issued an amendment to the accounting standards related to the accounting for revenue in arrangements with multiple deliverables including how the arrangement consideration is allocated among delivered and undelivered items of the arrangement. Among the amendments, this standard eliminates the use of the residual method for allocating arrangement consideration and requires an entity to allocate the overall consideration to each deliverable based on an estimated selling price of each individual deliverable in the arrangement in the absence of having vendor-specific objective evidence or other third party evidence of fair value of the undelivered items. This standard also provides further guidance on how to determine a separate unit of accounting in a multiple-deliverable revenue arrangement and expands the disclosure requirements about the judgments made in applying the estimated selling price method and how those judgments affect the timing or amount of revenue recognition. This standard will become effective for the Company on January 1, 2011.

In October 2009, the FASB issued an amendment to the accounting standards related to certain revenue arrangements that include software elements. This standard clarifies the existing accounting guidance such that tangible products that contain both software and non-software components that function together to deliver the product’s essential functionality, shall be excluded from the scope of the software revenue recognition accounting standards. Accordingly, sales of these products may fall within the scope of other revenue recognition accounting standards or may now be within the scope of this standard and may require an allocation of the arrangement consideration for each element of the arrangement. This standard will become effective for the Company on January 1, 2011.

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, 2010. 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.

NOTE 2-GOING CONCERN

As of December 31, 2010, the Company has a working capital deficit of $3,712,062 and total shareholders’ deficit of $2,503,370.  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, 2010, there are several non-cash items:  $391,272 is a non-cash deferred gain on the terminal transaction, $337,354 is due to a non-cash clawback provision and $103,511 is attributed to a derivative liability.  Additionally, $909,960 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
 
The Company entered into a lease commitment April 1, 2007.  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 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.

 
25

 

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, 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, 2010, 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, 2010 and 2009, the Company realized a gain on sale/leaseback of $391,278 for each year.
 
NOTE 4 – EQUIPMENT
 
The following is a summary of this category:

   
December 31, 2010
   
December 31, 2009
 
   
 
   
 
 
Machinery and equipment
  $ 514,565     $ -  
Vehicles
    47,427       47,427  
Leasehold improvements
    23,789       10,264  
Office equipment
    3,334       3,334  
Subtotal
    589,115       61,025  
Less: Accumulated depreciation
    (69,052 )     (28,366 )
Total
  $ 520,063     $ 32,659  

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 5), has a useful life of seven years, vehicles’ useful life is five years and office equipment is being depreciated over three years.

NOTE 5 – 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.
 
 
26

 
 
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 6 – FAIR VALUE OF FINANCIAL INSTRUMENTS

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, 2010, the valuations resulted in a loss on derivatives of $67,673 and a gain on contract clawback provision of $71,406 for a net gain of $3,733.

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
   
$
-
 
 
December 31, 2009
                                       
Description
  
Level 1
     
Level 2
     
Level 3
     
Total Realized
Gain (Loss) due to
valuation
     
Total Unrealized
Gain (Loss) due to
valuation
 
                               
Goodwill
 
$
-
   
$
-
   
$
1,559,240
   
$
-
   
$
-
 
Total
 
$
-
   
$
-
   
$
1,559,240
   
$
-
   
$
-
 
 
NOTE 7 - NOTES RECEIVABLE  / INTEREST RECEIVABLE
 
On November 6, 2003, Mr. Stuart Sundlun acquired 1,200 units of Intercontinental Fuels, LLC (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 is 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.

 
27

 
 
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, 2010 and 2009 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, 2009 and 2010.
 
A schedule of the balances at December 31, 2010 and 2009 is as follows:

   
December 31, 2010
     
December 31, 2009
 
             
Sundlun, net of unamortized discount
 
$
703,430
   
$
635,862
 
                 
Total notes receivable
 
$
703,430
   
$
635,862
 
Less:  current portion
   
(703,430
)
   
-
 
Total long-term notes receivable
 
$
-
   
$
635,862
 
 
NOTE 8 - 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.

Proved oil and gas properties: As of December 31, 2010, the Company’s Felix Brandt oil and gas leases include eight 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. Due to our significant net loss carryforward, we do not expect to pay any federal income taxes on future net revenues provided from the Brandt lease production. Therefore, the pre-tax and after-tax estimate of discounted future net cash flows are both $118,590.
 
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, 2010, the Company has recorded a net asset of $35,821 and related liability of $36,689. Accretion for the year ended December 31, 2010 was $868.

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.
 
 
28

 
 
The oil and gas related asset values at December 31, 2010 and December 31, 2009 were as follows:
 
   
December 31, 2010
     
December 31, 2009
 
                 
Tangible drilling costs
 
$
116,603
   
$
-
 
Proved oil and gas properties
   
71,060
     
-
 
Asset retirement cost
   
35,821
     
-
 
Impairment
   
(47,481
)
   
-
 
Accumulated DD&A
   
(20,724
)
   
-
 
Total
 
$
155,279
   
$
-
 

NOTE 9 – 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 8 below. 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, 2009 and 2010 and has determined that the fair value of the reporting unit exceeds its carrying amount and hence the goodwill is not impaired.
 
NOTE 10 – ACCRUED LIABILITIES / ACCRUED LIABILITIES –RELATED PARTY

Other liabilities and accrued expenses consisted of the following as of December 31, 2010 and 2009:
 
   
December 31, 2010
     
December 31, 2009
 
             
Accrued accounting and legal fees
 
$
115,000
   
$
119,000
 
Customer deposits
   
110,000
     
110,000
 
Property and payroll tax accrual
   
76,113
     
76,446
 
Asset retirement obligation
   
36,689
     
-
 
Deferred lease liability
   
33,799
     
25,122
 
Total accrued liabilities
 
$
371,601
   
$
330,568
 
                 
Accrued salaries-related party
 
$
909,960
   
$
1,023,687
 

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.

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.

 
29

 

NOTE 11 - NOTES PAYABLE
 
   
December 31, 2010
     
December 31, 2009
 
                 
Note payable  - Stuart Sundlun, bearing interest of 10% per annum, due August 7, 2011
 
$
1,500,000
   
$
1,500,000
 
Note payable - Bill Gaines, non interest bearing, due on demand
   
-
     
9,000
 
Note payable - Gulf Coast Fuels, bearing interest of $25,000
   
275,000
     
275,000
 
Demand note - Perales, non interest bearing, due May 31, 2011
   
50,000
     
-
 
Note payable - Asher, bearing interest of 8% per annum, due May 13, 2011, net of discount of $26,807
   
30,693
     
-
 
Notes payable - BWME, bearing interest at 8% per annum, due September 2, 2013
   
400,000
     
-
 
Note payable - GMAC, bearing interest of 11.7% per annum with 60 monthly payments of $895, due May 13, 2013
   
22,403
     
30,101
 
Total notes payable
 
$
2,278,096
   
$
1,814,101
 
Less: current portion
   
(1,864,251
)
   
(291,618
)
Long term note payable
 
$
413,845
   
$
1,522,483
 
 
On August 11, 2010, the Company issued a convertible promissory note to Asher Enterprises, Inc., in the amount of $57,500. The note has a maturity date of May 13, 2011 and has 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. The Company has the right to redeem the note for 150% of the redemption amount and accrued interest. See Note 13 for a complete discussion of the derivative treatment and accounting.

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, unless $50,000 is paid prior to May 1, 2011, in which case the debt will be considered fully paid, resulting in a gain to the Company of $10,000.
 
The table below reflects the aggregate principal maturities of long-term debt for years ended December 31:

   
Principal
 
       
2011
 
 $
1,864,251
 
2012
   
9,615
 
2013
   
404,230
 
2014
   
-
 
2015
   
-
 
Total
 
$
2,278,096
 

NOTE 12 - 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.

 
30

 

NOTE 13 – DERIVATIVE LIABILITY
 
Based on current guidance, the Company concluded that the convertible note payable to Asher referred to in Note 11 was 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.
 
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 note contained embedded derivatives that were analyzed. Certain features of the Asher note 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 note 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, 2010.

Below is detail of the derivative liability balances as of December 31, 2010 and December 31, 2009.

Derivative Liability
  
December 31, 2009
     
Additions
     
Gain (loss)
from valuation
     
December 31, 2010
 
                         
Asher note / BWME notes
   
-
   
$
35,838
   
$
(60,323
)
 
$
96,161
 
                                 
Haag warrants
   
-
     
-
     
(7,350
)
   
7,350
 
Total
   
-
   
$
35,838
   
$
(67,673
)
 
$
103,511
 

NOTE 14 – 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, 2010 and December 31, 2009, the Company had 107,260,579 and 93,260,579 shares issued and outstanding, respectively.
 
On February 20, 2009, the Company authorized restricted share issuances to the Board of Directors. Both Mr. Byrd and Mr. Wooley were granted 1,500,000 shares each and Ms. Behrens was granted 500,000 shares, resulting in an expense to the Company of $52,500 based on the fair market value of the shares at the issuance date.

On March 20, 2009, the Board approved a stock issuance of 1,000,000 shares of restricted common stock to Stuart Sundlun for consulting services.  This issuance resulted in an expense to the Company of $19,000, based on the stock’s market price at date of issuance.

In May 2009, the Company settled its lawsuit against CapNet Securities Corporation and related entities. The settlement called for the issuance of 4,500,000 shares of restricted stock to CapNet Securities Corporation and 1,000,000 shares of restricted stock to be issued to CapNet Risk Management, Inc. The settlement and stock issuance resulted in a net gain to the Company of $7,896, based upon the stock’s market price at date of issuance.

 
31

 

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, 5, 8, 12, 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.
 
As a result of the above common stock issuances, as of December 31, 2010, there were 107,260,579 shares outstanding.
 
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. As of December 31, 2010 and December 31, 2009 there are no shares issued and outstanding.
 
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.

DIVIDENDS

Dividends 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, 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 either series receive dividends of more than percent (1%) in any fiscal year. Each share of both series shall rank on parity with each other share of preferred stock, irrespective of series, with respect to dividends at the respective fixed or maximum rates for such series.

NOTE 15 - 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.

 
32

 

In November 2007, the Company entered into an agreement with Ms. Nancy Finney, the Company’s Controller. In addition to monthly compensation, Ms. Finney was entitled to 500,000 options, vesting over 24 months as certain milestones were met. In accordance with current guidance, these options will be 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.

NOTE 16 – 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, 2010 and 2009.

   
For the years ended December 31,
 
   
2010
   
2009
 
Numerator:
           
Basic net income (loss)
  $ (277,802 )   $ 23,029  
Diluted net income (loss)
  $ (277,802 )   $ 23,029  
                 
Denominator:
               
Basic weighted average common shares outstanding
    99,512,634       90,731,812  
Effect of dilutive securities
               
Convertible note - Asher
    1,280,990       0  
Dilutive weighted average common shares outstanding
    100,793,624       90,731,812  
Basic net income (loss) per share
  $ ( 0.00 )   $ 0.00  
Diluted net income (loss) per share
  $ ( 0.00 )   $ 0.00  
 
As of December 31, 2010, Adino had 107,260,579 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, 2010, Adino had 1,000,000 earned options outstanding to employees and consultants, exercisable between $0.10 to $0.35 each.  Using an average share price for the year ended December 31, 2010 of $0.023, the options result in no additional dilution to the Company.
 
The Company calculated the dilutive effect of the convertibility of the Asher note, resulting in additional weighted average share additions of 1,280,990 for the year ended December 31, 2010. The effect on earnings per share from the Company’s BWME 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.

NOTE 17 – 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 8 for further information related to the Company’s accounting for uncertainty in income taxes.

During 2010, the Company incurred a net loss and therefore, had no tax liability.  During 2009, the Company had net income that was fully absorbed by the net loss carry forward. The Company also does not have any material uncertain income tax positions.  The net deferred tax asset generated by the loss carry forward has been fully reserved.  The cumulative net operating loss carry forward is approximately $10,469,764 and $10,191,962 at December 31, 2010 and 2009, respectively, and will expire in the years 2019 through 2029.

 
33

 

 At December 31, 2010 and 2009, the deferred tax assets consisted of the following:

   
December 31, 2010
   
December 31, 2009
 
             
Net operating loss
  $ 3,559,720     $ 3,441,095  
Less: Valuation allowance
  $ (3,559,720 )   $ (3,441,095 )
Net deferred tax asset
  $ -     $ -  

NOTE 18 – 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, in 2009, the Company recorded a discount on the note principal of $179,671.  This amount will amortize until the note’s maturity in August 2011.

NOTE 19 – LAWSUIT SETTLEMENT

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 NARC was in default. The amount outstanding under the note was $725,733. In addition, Adino’s notes and debentures to Dr. 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 Energy 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.  In 2008, gain was recognized for 9 months or $74,019.  Gain recognized for 2009 was $98,692.

As of May 1, 2009, the Company settled all claims with all parties in the lawsuit known as Adino Energy Corporation v. CapNet Securities Corporation, et. al.    In the settlement, the Company issued 4,500,000 shares of restricted common stock to CapNet Securities Corporation and 1,000,000 shares of restricted common stock to CapNet Risk Management.  All shares issued are to be restricted until January 1, 2012.  Beginning January 1, 2012 and in every six month period thereafter, no more than 250,000 of the CapNet Risk Management shares and no more than 1,000,000 of the CapNet Securities Corporation shares may be released for sale.  The Company paid no cash to any involved party as a result of the settlement.  The Company realized a gain of $7,896 on the transaction, based on the stock’s market price at date of issuance.

 NOTE 20 – CONCENTRATIONS

The following table sets forth the amount and percentage of revenue from those customers that accounted for at least 10% of revenues for the years ended December 31, 2010 and 2009.

    
Year Ended
December 31,
2010
   %     
Year Ended
December 31,
2009
   
%
 
             
   
           
   
 
Customer A
  $
13,402
   
1
%   $
214,200
   
10
%
                             
Customer B
  $
1,476,000
   
74
%   $
353,103
   
16
%
                             
Customer C
  $
142,642
   
7
%   $
761,750
   
34
%
                             
Customer D
  $
61,110
   
3
%   $
462,746
   
21
%
                             
Customer E
  $
251,042
   
13
%   $
-
   
-
%
 
 
34

 
 
The Company had one customer that represented 100% of outstanding receivables at December 31, 2010 and one customer representing 79% of outstanding receivables at December 31, 2009.
 
NOTE 21 – 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, 2010, and the related discounted future net cash flows are based on estimates prepared by independent petroleum engineers. The following reserve quantity and future net cash flow information for 2010 was prepared by Corridor Resources, LLC (“CR”), independent petroleum engineers.

Oil reserves
 
   
Crude Oil
 
    
(Net Bbls)
 
December 31, 2009
    -  
Revisions of previous estimates
    -  
Purchase of reserves
    3,490  
Extensions, discoveries and other additions
    3,720  
Sale of reserves
    -  
Production
    (1,000 )
          
December 31, 2010
    6,210  

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 as of December 31, 2010.

 
35

 

Costs Incurred

Capitalized Costs Relating to Oil and Gas Producing Activities

   
2010
 
         
Unproved oil and gas properties
 
$
59,060
 
Proved oil and gas properties
   
223,484
 
Total
   
282,544
 
Accumulated depreciation, depletion, amortization and valuation allowances
   
(68,205
)
         
Total capitalized costs relating to oil and gas producing activities
 
$
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 year ended December 31, 2010:

   
2010
 
       
Property acquisition costs:
       
Unproved
 
$
59,060
 
Proved
   
71,060
 
Exploration costs
   
-
 
Development costs
   
116,603
 
Asset retirement cost
   
35,821
 
Total costs incurred
 
$
282,544
 

For results of operations incurred in the oil and gas exploration activities during 2010, see Note 23, Segment Reporting.  The Company did not capitalize costs associated with any exploratory wells during 2010.

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:

        
 
2010
 
       
Future cash inflows
  $ 451,160  
Future oil and natural gas operation expenses
    (327,680 )
Future development costs
    -  
Future income tax expenses
    -  
Future net cash flows
    123,480  
10% annual discount for estimating timing of cash flow
    (4,890 )
Standardized measure of discounted future net cash flow
  $ 118,590  

 
36

 

NOTE 22 – SEGMENT REPORTING

On July 1, 2010, the Company purchased PetroGreen Energy, LLC and AACM3, LLC, jump-starting its re-entry into the oil and gas exploration and production industry.  To facilitate those operations, the Company started two new wholly owned subsidiaries, Adino Exploration, LLC and Adino Drilling, LLC.  All oil and gas operations are conducted under these two subsidiaries.  The Company maintains all fuel storage operations, autonomously, in IFL.

Revenue:
The new oil and gas segment experienced minimal revenues during 2010, with only 6 months of ownership in the mature oilfield assets.  The Company experienced significant expenses in subsidiary origination, office set-up, employees and the well workover program.  The net income of the combined oil and gas segment for the year 2010 is as follows:

   
Total
 
  
 
2010
 
Revenues
  $ 58,107  
         
Production and lease operating expenses
    179,464  
Revenue sharing royalties
    8,902  
Impairment of oil and natural gas properties
    47,481  
Accretion of asset retirement obligation
    -  
Depreciation, depletion and amortization
    5,091  
Total costs
    240,938  
         
Pretax income (loss) from producing activities
    (182,831 )
Income tax expense
     
Results of oil and natural gas producing activities
       
(excluding overhead and interest costs)
  $ (182,831 )

There were no corresponding revenue or expenses for 2009, as the oil and gas operations were acquired on July 1, 2010.

Although the revenues generated from the oil and gas operations were not material to the Company as a whole, management anticipates increased revenues and stabilized expenses for 2011, primarily based on full year reporting, current lease development plans and operational efficiencies.

Assets
Total Company assets at December 31, 2010 were $3,738,767.  The oil and gas acquisition substantially added to the Company’s asset base. At December 31, 2010, total net oil and gas assets were $719,950 or 19.3% of the total.

   
December 31, 2010
 
         
Machinery and equipment, net of depreciation
 
$
505,611
 
Oil and gas properties:  proved, net of depletion and impairment
   
119,458
 
Oil and gas properties:  unproved
   
59,060
 
Asset retirement cost
   
35,821
 
Total net oil and gas assets
 
$
719,950
 

 
37

 

NOTE 23 – SUBSEQUENT EVENTS

On January 10, 2011, the Company entered into several convertible notes totaling $272,500 with a group of investors.  The 6% non-amortizing, two year notes mature on January 9, 2013 and are convertible at $0.35 at the option of the investor.  Interest is being accrued to maturity.

During the first quarter of 2011, Asher Enterprises, Inc. elected to convert a portion of its outstanding note receivable with the Company on three separate occasions.  The conversions were made in accordance with the note agreement and resulted in a reduction of the note payable balance of $34,000, common stock shares issued of 1,862,833 and a loss on conversion of $30,179.

There were no additional subsequent events through March 31, 2011, 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.

 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, 2010. 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, 2010, 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-B.  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, 2010, 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, 2010, based on the criteria established in "Internal Control-Integrated Framework" issued by the COSO.

 
38

 

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, 2010, 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.  Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this annual report.

Corrective Action

Management plans to address the structure of the Board of Directors and discuss adding an audit committee during 2011.

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, 2010, 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
 
71
 
Chairman of the Board of Directors
Timothy Byrd
 
48
 
Chief Executive Officer, Chief Financial Officer and Director
Peggy Behrens
 
54
 
Secretary and Director
Iftikhar Dean
 
63
 
President and Director

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.

TIMOTHY G. BYRD, SR., CHIEF EXECUTIVE OFFICER, CHIEF FINANCIAL OFFICER AND DIRECTOR
Mr. Byrd became the Company’s CEO, CFO and director in December 2001. Prior to then, Mr. Byrd was President of Innovative Capital Markets, an advisory firm that developed growth strategies for corporations through strategic alliances and mergers and acquisitions.

PEGGY BEHRENS, SECRETARY AND DIRECTOR
Ms. Behrens joined Adino in 1998 as Secretary and director. Prior to 1998, Ms. Behrens worked as the Administrator and Director of Nurses from 1996-1998 for Health Link Home Care.

Ms Behrens resigned as a director and Secretary in December 2010.

IFTIKHAR DEAN, PRESIDENT AND DIRECTOR
Mr. Dean joined the Company as president and a director in December 2010. Mr. Dean is president of Sunco Group, LLC (“Sunco”) of Houston, Texas, a fuel trading and terminaling company since 2008. From 1999 to 2008, Mr. Dean was Chief Executive Officer of Jade Global Trading Corporation, a fuel trading company. Mr. Dean was appointed to the Board pursuant to a memorandum of understanding entered into with the Company whereby the Company agreed to appoint him as president and as a member of the administration and management committee of the Board of Directors. The Company and Mr. Dean later agreed that he should be appointed as a director of the Company in lieu of being appointed as a member of the administration and management committee.

All officers and directors listed above will remain in office until the next annual meeting of our stockholders and until their successors have been duly elected and qualified. There are no agreements with respect to the election of directors. Officers are appointed annually by our Board of Directors and each Executive Officer serves at the discretion of our Board of Directors. We do not have any standing committees.

 
39

 

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 five (5) 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.

We have reviewed the Section 16(a) filings made in connection with the Company’s stock. We believe that all persons subject to Section 16(a) of the Exchange Act in connection with their relationship with us have complied on a timely basis.

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.
 
·
Peggy Behrens, our Secretary and a director, did not file a Form 4 regarding a grant of 500,000 shares to her on November 24, 2010. The failure to file this form was due to an administrative oversight.

CODE OF ETHICS
The Company has adopted a code of ethics applicable to our Chief Executive Officer, Chief Financial Officer, 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.

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
 
2009
    180,000       53,743       22,500       -0-       -0-       256,243  
                                                     
Sonny Wooley, Chairman
 
2010
    180,000       -0-       15,500       -0-       -0-       195,500  
Sonny Wooley, Chairman
 
2009
    180,000       68,075       22,500       -0-       -0-       270,575  
                                                     
Nancy Finney, Controller
 
2010
    90,000       -0-       -0-       -0-       -0-       90,000  
Nancy Finney, Controller
 
2009
    90,000       27,089       -0-       7,213       -0-       124,302  

 
40

 

DIRECTOR COMPENSATION
 
Name
      
Fees Earned or 
Paid in Cash ($)
   
Stock Awards ($)
   
Total ($)
 
Peggy Behrens
 
 2010
    -0-       15,500 (1)     15,500  
Peggy Behrens
 
 2009
    -0-       7,500 (1)     7,500  

On February 20, 2009, the Company authorized the issuance of 1,500,000 shares to Mr. Byrd and Mr. Wooley and 500,000 shares to Ms. Behrens.  This issuance resulted in an expense to the Company of $52,500 based on the fair market value of the shares at the issuance date. On March 26, 2009, our Board of Directors authorized issuance of 250,000 shares of stock per year to our directors as compensation for their service. On December 30, 2009, the Board decided not to issue any shares as directors’ compensation for 2009.

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.

OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END

The following table shows equity awards outstanding to our management at December 31, 2010.

Name
 
Number of Securities
Underlying Unexercised
Options (#)
Exercisable
 
Equity Incentive Plan
Awards: Number of
Securities Underlying
Unexercised Unearned
Options (#)
 
Option Exercise Price
 
Option Expiration Date
Nancy Finney
    100,000  
   
  $ 0.10  
December 31, 2012
Nancy Finney
    100,000  
   
  $ 0.10  
April 14, 2013
Nancy Finney
    50,000  
   
  $ 0.10  
June 30, 2013
Nancy Finney
    100,000  
   
  $ 0.10  
September 30, 2013
Nancy Finney
    50,000  
   
  $ 0.10  
March 31, 2014
Nancy Finney
    100,000  
   
  $ 0.10  
September 30, 2014

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

EQUITY COMPENSATION PLAN INFORMATION

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