ADINO ENERGY CORP - FORM 10-Q - November 14, 2011

Attached files

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EXCEL - IDEA: XBRL DOCUMENT - ADINO ENERGY CORP	Financial_Report.xls
EX-32.1 - EXHIBIT 32.1 - ADINO ENERGY CORP	v239790_ex32-1.htm
EX-31.1 - EXHIBIT 31.1 - ADINO ENERGY CORP	v239790_ex31-1.htm
EX-31.2 - EXHIBIT 31.2 - ADINO ENERGY CORP	v239790_ex31-2.htm
EX-32.2 - EXHIBIT 32.2 - ADINO ENERGY CORP	v239790_ex32-2.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2011

¨	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 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 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

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date: At November 14, 2011, there were 122,910,232 shares of common stock outstanding.

TABLE OF CONTENTS

		Page No.
PART I FINANCIAL INFORMATION

Item 1.	Financial Statements	3
	Consolidated Balance Sheets – September 30, 2011 (Unaudited) and December 31, 2010	3
	Unaudited Consolidated Statements of Operations-Three and Nine months ended September 30, 2011 and 2010	4
	Unaudited Consolidated Statement of Changes in Stockholder’s Deficit – Nine months ended September 30, 2011	5
	Unaudited Consolidated Statements of Cash Flows – Nine months ended September 30, 2011 and 2010	6
	Notes to Unaudited Consolidated Financial Statements	7

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
Item 3.	Quantitative and Qualitative Disclosures About Market Risks	25
Item 4T.	Controls and Procedures	25

PART II OTHER INFORMATION

Item 1.	Legal Proceedings	26
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	26
Item 3.	Defaults Upon Senior Securities	26
Item 4.	Removed and Reserved	26
Item 5.	Other Information	26
Item 6.	Exhibits	27

Signatures		28

ITEM 1. FINANCIAL STATEMENTS

ADINO ENERGY CORPORATION

Consolidated Balance Sheets

AS OF SEPTEMBER 30, 2011 AND DECEMBER 31, 2010

	September 30, 2011			December 31, 2010
	(Unaudited)
ASSETS
Cash in bank	$	176,856		$	282,272
Accounts receivable		37,028			9,615
Deposits and prepaid assets		69,217			64,562
Notes receivable - current portion, net of unamortized discount of $0 and $46,570, respectively		750,000			703,430
Interest receivable		375,208			375,208
Inventory		1,722			-
Total current assets		1,410,031			1,435,087

Fixed assets, net of accumulated depreciation of $75,438 and $47,866, respectively		187,757			165,648
Oil and gas properties (full cost method), net of accumulated amortization, depreciation, depletion, and asset impairment
Proved		394,843			155,279
Unproved		3,990			59,060
Goodwill		1,559,240			1,566,379
Discontinued operations - net assets held for sale		-			357,314
Total non-current assets		2,145,830			2,303,680
TOTAL ASSETS	$	3,555,861		$	3,738,767

LIABILITIES AND STOCKHOLDERS’ DEFICIT
Accounts payable	$	477,619		$	413,515
Accounts payable - related party		76,375			47,200
Accrued liabilities		377,566			371,601
Accrued liabilities - related party		954,659			909,960
Contract clawback provision		402,733			337,354
Notes payable - current portion		1,903,715			1,864,251
Interest payable		795,759			660,000
Derivative liability		122,402			103,511
Deferred gain - current portion		391,272			391,272
Discontinued operations - liabilities held for sale		-			44,884
Total current liabilities		5,502,100			5,143,548

Deferred gain, net of current portion		391,285			684,744
Notes payable, net of current portion		679,264			413,845
TOTAL LIABILITIES		6,572,649			6,242,137

STOCKHOLDERS’ DEFICIT
Capital stock, $0.001 par value, 500 million shares authorized, 122,910,232 and 107,260,579 shares issued and outstanding at September 30, 2011 and December 31, 2010, respectively		122,910			107,260
Additional paid in capital		14,107,944			13,785,442
Retained deficit		(17,247,642	)		(16,396,072	)
Total stockholders’ deficit		(3,016,788	)		(2,503,370	)

TOTAL LIABILITIES AND STOCKHOLDERS’ DEFICIT	$	3,555,861		$	3,738,767

See accompanying notes to the financial statements

ADINO ENERGY CORPORATION

Consolidated Statements of Operations

FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2011 AND 2010

(Unaudited)

	Three months ended						Nine months ended
	September 30			September 30			September 30			September 30
	2011			2010			2011			2010

REVENUES AND GROSS MARGINS
Terminal operations	$	456,000		$	365,817		$	1,418,000		$	1,488,483
Oil and gas operations		137,123			23,202			258,581			23,202
Total revenues		593,123			389,019			1,676,581			1,511,685

OPERATING EXPENSES
Cost of product sales		16,264			9,427			36,907			239,542
Payroll and related expenses		46,541			5,613			158,602			5,613
Terminal management		101,490			100,090			302,070			300,070
General and administrative		212,293			197,117			561,425			515,745
Legal and professional		133,220			62,828			324,447			177,825
Consulting fees		443,511			242,749			870,479			558,680
Repairs		3,087			1,444			5,292			7,807
Depreciation expense		22,718			17,465			67,119			22,550
Operating supplies		15,170			19,961			20,322			19,961
Total operating expenses		994,294			656,694			2,346,663			1,847,793

OPERATING LOSS		(401,171	)		(267,675	)		(670,082	)		(336,108	)

OTHER INCOME AND EXPENSES
Interest income		7,033			17,341			46,898			49,386
Interest expense		(75,707	)		(49,317	)		(212,569	)		(129,789	)
Gain from lawsuit/sale leaseback		97,820			98,237			293,460			293,876
Gain (loss) on derivative		35,419			(76,314	)		28,144			(76,314	)
Gain (loss) on change in fair value of clawback		(64,683	)		114,815			(65,379	)		114,815
Total other income and expense		(118	)		104,762			90,554			251,974

(LOSS) FROM CONTINUING OPERATIONS	$	(401,289	)	$	(162,913	)	$	(579,528	)	$	(84,134	)

DISCONTINUED OPERATIONS
Loss from operations of discontinued Adino Drilling, LLC		-			-			(272,042	)		-
NET INCOME (LOSS)	$	(401,289	)	$	(162,913	)	$	(851,570	)	$	(84,134	)

Net income (loss) per share, basic and diluted	$	0.00		$	(0.00	)	$	(0.01	)	$	0.00

Weighted average shares outstanding, basic and diluted		117,505,341			104,151,883			112,099,157			97,203,802

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

ADINO ENERGY CORPORATION

Consolidated Statement of Changes in Stockholders’ Deficit

FOR THE PERIOD ENDED SEPTEMBER 30, 2011

(Unaudited)

	Shares		Amount		Additional Paid in Capital		Retained Deficit			Total
Balance December 31, 2010		107,260,579	$	107,260	$	13,785,442	$	(16,396,072	)	$	(2,503,370	)

Shares issued in debt conversion		3,899,653		3,900		53,600		-			57,500

Derivative settlement		-		-		38,544		-			38,544

Shares issued for services		11,750,000		11,750		230,358		-			242,108

Net (loss)		-		-		-		(851,570	)		(851,570	)

Balance September 30, 2011		122,910,232	$	122,910	$	14,107,944	$	(17,247,642	)	$	(3,016,788	)

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

ADINO ENERGY CORPORATION

Consolidated Statements of Cash Flows

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2011 AND 2010

(Unaudited)

	September 30, 2011			September 30, 2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Loss	$	(851,570	)	$	(84,134	)
Adjustments to reconcile net income (loss) to net cash (used in) operating activities:
Depreciation, depletion and accretion		80,770			22,550
Amortization of discount on note receivable		(46,570	)		(49,308	)
Bad debt expense		-			30,000
Shares issued for services		242,108			75,700
Amortization of note discount		50,031			6,504
Change in fair value of derivative liability		(28,144	)		76,314
Loss on change in fair value of clawback provision		65,379			(114,815	)
Gain on lawsuit settlement		(293,460	)		(293,459	)
Loss on sale of subsidiary		252,524			-
Change in operating assets and liabilities:
Accounts receivable		(27,413	)		55,734
Inventory		(1,722	)		-
Other assets		(4,654	)		(13,713	)
Accounts payable and accrued liabilities		333,660			(72,501	)
Net cash (used in) operating activities	$	(229,061	)	$	(361,128	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Purchases of equipment		(277,185	)		(32,772	)
Net cash (used in) investing activities	$	(277,185	)	$	(32,772	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowing on debt		453,500			457,500
Principal payments on note payable		(55,569	)		(12,690	)
Net cash provided from financing activities	$	397,931		$	444,810

Net change in cash and cash equivalents		(108,315	)		50,910
Cash and cash equivalents, beginning of period		285,171			502,542
Cash and cash equivalents, end of period	$	176,856		$	553,452

Cash paid for taxes	$	-		$	-
Cash paid for interest	$	12,582		$	12,285

Non-cash transactions:
Stock issued in debt conversion	$	57,500		$	-
Derivative liability	$	85,579		$	-
Derivative settlement	$	38,544		$	-
Revision of asset retirement obligation	$	3,669		$	19,728
Acquisition purchased with stock	$	-		$	150,000
Note discount	$	-		$	35,838
Contract clawback provision	$	-		$	293,945

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

ADINO ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

NOTE 1 - ORGANIZATION

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, work-over 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 and in October, 2001 changed its name to Consolidated Minerals Management, Inc. 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 was a licensed Texas oilfield operator currently operating 14 wells on two leases covering approximately 300 acres in Coleman County, Texas. Petro Energy also owned a drilling rig, two service rigs and associated tools and equipment. The Company also acquired the operator license held by the principal of Petro Energy.

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

NOTE 2 - BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES

Basis of presentation

The accompanying unaudited interim consolidated financial statements of Adino Energy Corporation have been prepared in accordance with accounting principles generally accepted in the United States of America and the rules of the Securities and Exchange Commission (“SEC”), and should be read in conjunction with the audited financial statements and notes thereto contained in Adino Energy Corporation’s Annual Report filed with the SEC on Form 10-K. In the opinion of management, all adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of financial position and the results of operations for the interim periods presented have been reflected herein. The results of operations for interim periods are not necessarily indicative of the results to be expected for the full year.

Significant accounting policies

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 nine months ended September 30, 2011 and the year ended December 31, 2010, we had no reserve for doubtful accounts as all of our receivables were collected early in the subsequent period and had no expectation of loss. Management assesses the need for an allowance for doubtful accounts based upon the financial strength of our customers, historical experience with our customers and the aging of the amounts due.

Cash Equivalents

For purposes of reporting cash flows, the Company considers all short-term investments with an original maturity of three months or less to be cash equivalents. We had no cash equivalents at either September 30, 2011 or December 31, 2010.

Inventory

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

Property and Equipment

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

Oil and Gas Producing Activities

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

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

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

Derivatives

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

Asset Retirement Obligation

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

Revenue Recognition

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

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

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

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

Segment Reporting

The Company is required to present segment reporting (also called line of business reporting) in its financial reports 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.. 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 must 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.

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 19 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.

Income (Loss) Per Share

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

Stock-Based Compensation

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

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

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

Impairment of Long-Lived Assets

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

For the quarters ended September 30, 2011 and 2010, Adino evaluated and determined that no impairment was warranted on the fixed assets of the Company. Additionally, no impairment was required on the oil and gas assets of the Company. There was no change to the impairment analysis performed at the December 31, 2010 audit and no indicators of impairment at the review. See Notes 9 and 10 for a more thorough discussion of the Company’s fixed assets and oil and gas assets as of September 30, 2011.

Goodwill

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

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

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 September 30, 2011 or December 31, 2010.

Fair Value of Financial Instruments

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

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

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

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

Level 1:

Quoted prices in active markets for identical assets or liabilities.

Level 2:

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

Level 3:

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

Reclassification

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

NOTE 3-GOING CONCERN

As of September 30, 2011, the Company has a working capital deficit of $4,092,069 and total stockholders’ deficit of $3,016,788. 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 September 30, 2011, $391,272 is a non-cash deferred gain on the terminal transaction. See Note 4 for a complete explanation of the deferred settlement gain. Additionally, $954,659 of the outstanding current liabilities is due to certain officers and directors for prior years’ accrued compensation. These officers and directors 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 fuel terminal storage and oil and gas operations and merger and acquisition opportunities including the expansion of existing business opportunities. The Company expects these growth opportunities to be financed by a combination of equity and debt capital; however, in the event the Company is unable to obtain additional debt and equity financing, the Company may not be able to continue its operations.

NOTE 4-LEASE COMMITMENTS

On April 1, 2007, IFL agreed to lease a fuel storage terminal from 17617 Aldine Westfield Road, LLC for 18 months at $15,000 per month. The lease contained 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.

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

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

The transactions that led to the above two leases both resulted in gains to the Company. The lawsuit settlement just prior to the lease with 17617 Aldine Westfield Road, LLC resulted in a gain to the Company of $1,480,383. The Company amortized this amount over the life of the capital asset, or 15 years.

At the expiration of the capital lease, September 30, 2008, the above 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 was $1,956,392. This amount is being amortized over the life of the Lone Star operating lease, or 60 months. The operating lease expires on September 30, 2013. This treatment is consistent with sale leaseback gain recognition rules.

For the nine months ended September 30, 2011 and 2010, the Company recognized $293,460 and $293,876 respectively, in gain on sale/leaseback.

NOTE 5 – PETRO ENERGY ACQUISITION PURCHASE PRICE ALLOCATION

The Company’s acquisition of Petro Energy (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.

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

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

NOTE 6 – SALE OF ADINO DRILLING, LLC

On March 31, 2011, the Company sold the membership shares of Adino Drilling, LLC to a related party. Under the terms of the agreement, the Company realized a reduction in accrued liability of $100,000 and acquired a $500,000 six year, 5.24% interest note receivable, for a total sale price of $600,000. The sale resulted in a gain to the Company of $247,376; however the transaction’s related party note of $500,000 is not allowed for reporting purposes, therefore the Company realized a reportable loss of $252,624. Adino’s management believes that the sale of the drilling rig and associated equipment was in the best interest of the Company and the shareholders. The rig held by the Company was primarily suited for drilling up to 3,500 feet. However, the Company is currently drilling shallower wells. This large rig would be uneconomical for drilling smaller wells. The Company has decided to contract with service companies that specialize in shallower wells, thus reducing drilling expense. The cash flow to be realized from the $500,000 note, accompanied by the decreased related party compensation of $100,000, is expected to increase Adino’s cash flow.

With the sale of Adino Drilling, LLC, the $7,139 of goodwill resulting from the original PetroGreen acquisition, discussed in Note 5 was written off. The transaction has been accounted for as a discontinued operation.

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

	Assets disposed at March 31, 2011		December 31, 2010

Cash	$	100	$	2,899
Fixed assets, net of depreciation of $34,837 and $21,186 at March 31, 2011 and December 31, 2010, respectively		350,702		354,415
Total assets		350,802		357,314

Accounts payable		5,317		44,472
Accounts payable - related party		-		412
Total liabilities		5,317		44,884
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Net assets - discontinued operations	$	345,485	$	312,430

NOTE 7 – 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 September 30, 2011, the valuations resulted in a gain on derivatives of $28,144 and a loss on contract clawback provision of $65,679 for a net loss of $37,235.

September 30, 2011
Description	Level 1		Level 2		Level 3		Total Realized Gain (Loss) due to Valuation at			Total Unrealized Gain (Loss) due to valuation

Goodwill	$	-	$	-	$	1,559,240	$	-		$	-

Notes payable - derivative		-		-		118,718		24,478			-

Haag warrants - derivative		-		-		3,684		3,666			-

Contract clawback provision		-		-		402,733		(65,379	)		-
Total	$	-	$	-	$	2,084,375	$	(37,235	)	$	-

December 31, 2010
Description	Level 1		Level 2		Level 3		Total Realized Gain (Loss) due to Valuation at September 30, 2010		Total Unrealized Gain (Loss) due to valuation

Goodwill	$	-	$	-	$	1,566,379	$	-	$	-

Asher /BWME notes - derivative		-		-		96,161		-		-

Haag warrants - derivative		-		-		7,350		-		-

Contract clawback provision						337,354		-		-
Total	$	-	$	-	$	2,007,244	$	-	$	-

At September 30, 2011, the Company had $1,559,240 of goodwill on the balance sheet. There was no gain or loss on valuation for the quarter or nine months ended September 30, 2011.

NOTE 8 - NOTES RECEIVABLE / INTEREST RECEIVABLE

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

On August 7, 2006, IFL repurchased the units sold to Mr. Sundlun. The entire amount due from Mr. Sundlun and payable to Mr. Sundlun is reported at gross (i.e., without offset) 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.

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

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

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

The note receivable from Mr. Sundlun matured on November 6, 2008. The Company extended the note’s maturity date to August 8, 2011 with no additional interest accrual to occur past November 6, 2008. Due to the fact that there will be no interest accrued on the note going forward, the Company recorded a discount on the note principal of $179,671. The discount was fully amortized as of August 8, 2011. As of September 30, 2011, the note’s extension or renegotiation was in discussion.

Interest accrued on the Sundlun note receivable was $375,208 at September 30, 2011 and December 31, 2010.

A schedule of the balances at September 30, 2011 and December 31, 2010 is as follows:

	September 30, 2011			December 31, 2010

Sundlun, net of unamortized discount of $0 and $46,570, respectively	$	750,000		$	703,430
Less: current portion		(750,000	)		(703,430	)
Total long-term notes receivable	$	-		$	-

NOTE 9 – FIXED ASSETS

The following is a summary of this category:

	September 30, 2011			December 31, 2010

Machinery and equipment	$	181,648		$	138,964
Vehicles		47,427			47,427
Leasehold improvements		30,786			23,789
Office equipment		3,334			3,334
Total assets - continuing operations		263,195			213,514
Less: Accumulated depreciation		(75,438	)		(47,866	)
Net assets - continuing operations		187,757			165,648
Machinery and equipment - Adino Drilling, LLC, discontinued as of 3/31/2011, net of accumulated depreciation		-			354,415
Total	$	187,757		$	520,063

On March 31, 2011, the Company sold the membership shares of Adino Drilling, LLC to a related third party. Adino Drilling, LLC’s assets were machinery and equipment, with a net book value of $350,701 at the time of sale.

The useful life for leasehold improvements is the duration of the lease on the IFL fuel terminal, through September 30, 2013. Machinery and equipment has a useful life of seven years, vehicles’ useful life is five years and office equipment is being depreciated over three years. Depreciation expense for the quarters ended September 30, 2011 and 2010 was $22,718 and $17,465, respectively.

NOTE 10 - OIL AND GAS PROPERTIES

Tangible drilling costs: The Company acquired tangible drilling equipment and proved oil and gas properties with the Petro Energy acquisition in July 2010. The tangible assets were valued based on the appropriate application of the market or cost approaches as of the date of acquisition. The fair value was estimated at the depreciable value of the current replacement costs based on the age and condition of the assets. During the second quarter of 2011, the Company drilled three new wells on the Leonard lease. Of the total cost of these wells, $264,725 is deemed tangible drilling costs and capitalized.

Proved oil and gas properties: As of September 30, 2011, 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. During the second quarter of 2011, the Company completed three oil wells on its James Leonard lease, acquired in the PetroGreen acquisition of July 2010. According to the reserve analysis conducted by an independent engineering firm, the estimated discounted net cash flow on both the Felix Brandt and James Leonard leases was $942,120 as of June 30, 2011. Due to our significant net loss carryforward, we do not expect to pay any federal income taxes on future net revenues provided from either the Brandt or Leonard lease production. Therefore, the pre-tax and after-tax estimate of discounted future net cash flows are both $942,120 and $118,590 at September 30, 2011 and December 31, 2010, respectively.

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. During the first quarter of 2011, the Company added an asset retirement liability for the James Leonard lease, based on the average cost to plug and abandon wells of similar type and structure in the area. The resulting liability of $6,000 was recorded at its present value of $3,669, with an offsetting asset adjustment to asset retirement cost. As of September 30, 2011 and December 31, 2010, the Company has recorded an asset of $39,490 and $35,821 and related liability of $43,164 and $36,689, respectively. Accretion for the quarter ended September 30, 2011 was $1,073.

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 no additional impairment was noted for the quarter or nine months ended September 30, 2011.

The Company performed a review of its unproved properties and noted no impairment for the quarter or nine months ended September 30, 2011.

The oil and gas related asset values at September 30, 2011 and December 31, 2010 were as follows:

	September 30, 2011			December 31, 2010

Tangible drilling costs	$	393,229		$	116,603
Proved oil and gas properties		71,060			71,060
Asset retirement cost		39,490			35,821
Impairment		(47,481	)		(47,481	)
Accumulated DD&A		(57,465	)		(20,724	)
Total	$	398,833		$	155,279

Depletion: Depletion, calculated using the units of production method was $19,654 and $36,741 for the three and nine months ended September 30, 2011. There was no corresponding expense during the same periods in 2010.

NOTE 11 – 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 13 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.

Additionally, the Company realized $7,139 of goodwill associated with the acquisition of PetroGreen and AACM3, LLC on July 1, 2010. The Company sold its wholly owned subsidiary, Adino Drilling, LLC as of March 31, 2011 and the goodwill of $7,139 was written off.

Adino evaluated the aggregate goodwill for impairment at September 30, 2011 and December 31, 2010. There were no impairment indicators. The Company has determined that the fair value of the reporting unit exceeds its carrying amount and hence the goodwill is not impaired.

NOTE 12 – ACCRUED LIABILITIES / ACCRUED LIABILITIES –RELATED PARTY

Other liabilities and accrued expenses consisted of the following as of September 30, 2011 and December 31, 2010:

	September 30, 2011		December 31, 2010

Accrued accounting and consulting fees	$	128,000	$	115,000
Customer deposits		110,000		110,000
Property and payroll tax accrual		62,353		76,113
Asset retirement obligation		43,164		36,689
Deferred lease liability		34,049		33,799
Total accrued liabilities	$	377,566	$	371,601

Accrued salaries-related party	$	954,659	$	909,960

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 current and prior years’ accrued compensation. They have agreed to postpone payment if necessary, should the Company need capital it would otherwise pay these individuals.

NOTE 13 - NOTES PAYABLE

	September 30, 2011			December 31, 2010

Note payable - Stuart Sundlun, bearing interest of 10% per annum, due August 7, 2011	$	1,500,000		$	1,500,000
Notes payable - Schwartz group, bearing interest at 6%, due January 9, 2013		272,500			-
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 notes, net of discount of $62,355 and $26,807 at September 30, 2011 and December 31, 2010, respectively		118,645			30,693
bearing interest of 8% per annum, due May 13, 2011, (balance $0.00 at 9/30/2011; $57,500 at 12/31/10)
bearing interest of 8% per annum, due February 16, 2012 (balance $53,000 at 9/30/2011; $0.00 at 12/31/10)
bearing interest of 8% per annum, due March 23,2012 (balance $53,000 at 9/30/2011; $0.00 at 12/31/10)
bearing interest of 8% per annum, due April 7, 2012 (balance $37,500 at 9/30/2011; $0.00 at 12/31/10)
bearing interest of 8% per annum, due June 12, 2012 (balance $37,500 at 9/30/2011; $0.00 at 12/31/10)
Notes payable - BWME, bearing interest at 8% per annum, due September 2, 2013		400,000			400,000
Note payable - GMAC, bearing interest of 11.7% per annum with 60 monthly payments of $895, due May 13, 2013		16,834			22,403
Total notes payable	$	2,582,979		$	2,278,096
Less: current portion		(1,903,715	)		(1,864,251	)
Long term note payable	$	679,264		$	413,845

On August 11, 2010, the Company issued a convertible promissory note to Asher Enterprises, Inc. (“Asher”), in the amount of $57,500. The note had a maturity date of May 13, 2011 and an annual interest rate of eight percent (8%) per annum. The holders have the right from and after the date of issuance, and until any time until the note is fully paid, to convert any outstanding and unpaid principal portion of the note, and accrued interest, into fully paid and non-assessable shares of common stock. The note has an initial conversion price of fifty eight percent (58%) of the 3 lowest closing bid prices for the 10 days preceding the conversion date and full reset provision. The note’s convertible feature was valued and resulted in a debt discount of $35,838, which is being amortized over the nine month note life, using the straight line method. In this case, using the straight line method approximates the effective interest method, given the short time to maturity. The Company has the right to redeem the note within 90 days from the date of issuance for 150% of the redemption amount and accrued interest. See Note 16 for a complete discussion of the derivative treatment and accounting of the Asher note.

During the first quarter of 2011, Asher converted $34,000 of the notes into the Company’s common stock, resulting in an issuance of 1,862,833 shares to Asher. During the second quarter of 2011, Asher converted the remaining balance of $23,500 into the Company’s common stock, resulting in an issuance of 2,036,820 shares to Asher. See Note 16 for a detailed description of each conversion.

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.

On January 10, 2011, the Company issued convertible promissory notes to investors in the amount of $272,500, to fund drilling activities associated with the recent Petro Energy acquisition. The notes have a maturity date of January 9, 2013, with interest accrued and paid at the option of the holder at an annual interest rate of six percent (6%) per annum. The holders have the right from and after the date of issuance, and until any time until the note is fully paid, to convert any outstanding and unpaid principal portion of the note, and accrued interest, into fully paid and non-assessable shares of common stock. The note has a fixed conversion price of $0.35.

During the second quarter of 2011, the Company issued two nine-month convertible promissory notes to Asher in the amount of $53,000 each. The notes have maturity dates of February 16, 2012 and March 23, 2012 and an annual interest rate of eight percent (8%) per annum. The holders have the right from and after the date of issuance, and until any time until the note is fully paid, to convert any outstanding and unpaid principal portion of the note, and accrued interest, into fully paid and non-assessable shares of common stock. The note has an initial conversion price of sixty five percent (65%) of the three lowest closing bid prices for the ten days preceding the conversion date.

During the third quarter of 2011, the Company issued two nine-month convertible promissory notes to Asher in the amount of $37,500 each. The notes have maturity dates of April 17, 2012 and June 12, 2012 and an annual interest rate of eight percent (8%) per annum. The holders have the right from and after the date of issuance, and until any time until the note is fully paid, to convert any outstanding and unpaid principal portion of the note, and accrued interest, into fully paid and non-assessable shares of common stock. The note due April 17, 2012 has an initial conversion price of sixty five percent (65%) of the three lowest closing bid prices for the ten days preceding the conversion date. The note due June 12, 2012 has an initial conversion price of fifty six percent (56%) of the three lowest closing bid prices for the ten days preceding the conversion date.

The Asher note’s convertible feature was valued and resulted in a debt discount which is being amortized over the nine month note lives, 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 within 90 days from the date of issuance for 135% of the redemption amount and accrued interest, from days 91-120, the Company has the right to redeem the notes for 145% of the redemption amount and accrued interest, and from days 121-180, the Company has the right to redeem the notes for 150% of the redemption amount and accrued interest. See Note 16 for a complete discussion of the derivative treatment and accounting of the Asher note.

NOTE 14 - 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 has been revalued at each successive balance sheet date. The current value of $402,733 at September 30, 2011, resulted in a loss on change in clawback valuation of $65,379 for the nine months then ended.

NOTE 15 – DERIVATIVE LIABILITY

Based on current guidance, the Company concluded that the convertible notes payable to Asher referred to in Note 16 were required to be accounted for as derivatives. 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 notes caused three other financial instruments held by the Company to be deemed derivatives: The BWME and Schwartz notes and the Haag warrants. All were valued as derivatives as of the date of the Asher note issuance (Haag warrants) or date of issuance (BWME and Schwartz notes) and revalued at December 31, 2010 and September 30, 2011.

Below is detail of the derivative liability balances as of September 30, 2011 and December 31, 2010.

Derivative Liability	December 31, 2010		Additions		Increase (Decrease) from valuation			September 30, 2011

Asher note / BWME notes / Schwartz notes	$	96,161	$	106,420	$	(83,863	)	$	118,718

Haag warrants		7,350		-		(3,666	)		3,684

Total	$	103,511	$	106,420	$	(87,529	)	$	122,402

The net gain of $18,891 is split between additions to derivative liability due to new notes of $85,579, a reduction of $38,544 to additional paid-in-capital for the derivative reduction attributable to the Asher note conversions discussed in Notes 13 and 16. The remaining $28,144 is reflected as gain on derivatives in the statement of operations.

NOTE 16 – 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, the Company had 107,260,579 shares issued and outstanding.

On February 22, 2011, Asher converted $10,000 of its note into 465,116 shares of the Company’s common stock. The conversion resulted in an increase of additional paid-in-capital of $6,648 due to the reduction of the associated derivative liability.

On March 8, 2011, Asher converted $12,000 of its note into 603,015 shares of the Company’s common stock. The conversion resulted in an increase of additional paid-in-capital of $7,959 due to the reduction of the associated derivative liability.

On March 22, 2011, Asher converted $12,000 of its note into 794,702 shares of the Company’s common stock. The conversion resulted in an increase of additional paid-in-capital of $7,987 due to the reduction of the associated derivative liability.

On April 4, 2011, Asher converted $15,000 of its note into 1,219,512 shares of the Company’s common stock. The conversion resulted in an increase of additional paid-in-capital of $10,183 due to the reduction of the associated derivative liability.

On April 12, 2011, Asher converted $8,500 of its note into 817,308 shares of the Company’s common stock. The conversion resulted in an increase of additional paid-in-capital of $5,767 due to the reduction of the associated derivative liability.

All note conversions were within the terms of the agreement.

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

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

On September 16, 2011, the Board of Directors granted 500,000 shares of Rule 144 stock to the Company’s controller, Nancy Finney, for services rendered. Ms. Finney relinquished the 500,000 fully vested options granted to her in 2007 within this transaction. Current guidance required the options to be revalued as of the day prior to the share grant. Using the Black-Scholes valuation model and an expected life of 1 year (remaining option life), volatility of 226%, and a discount rate of .09%, the Company has determined the aggregate value of the 500,000 options to be $5,643. The market price of the issued stock on date of grant was $0.022, resulting in stock expense to the Company of $11,000. The Company recorded an expense of $5,357 (market value – option value) on the transaction.

As a result of the above common stock issuances, there were 122,910,232 shares issued and outstanding as of September 30, 2011.

PREFERRED STOCK

In 1998, the Company amended its articles to authorize Preferred Stock. There are 20,000,000 shares authorized of Preferred Stock with a par value of $0.001. The shares are non-voting and non-redeemable by the Company. The Company further designated five series of its Preferred Stock: "Series 'A' $12.50 Preferred Stock" (2,159,193 shares authorized), "Series "A" $8.00 Preferred Stock," (1,079,957 shares authorized), Class “B” Preferred Stock Series 1 (666,660 shares authorized), Class “B” Preferred Stock Series 2 (666,660 shares authorized), and Class “B” Preferred Stock Series 3 (666,680 shares authorized). As of September 30, 2011 and December 31, 2010, there are no shares of Preferred Stock issued and outstanding.

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. The conversion ratio is three (3) shares of common stock per share of Series “A” $12.50 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 conversion ratio is three (3) shares of common stock per share of Series “A” $8.00 Preferred Stock.

The Class “B” Preferred Stock Series 1 is 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 $2.00 for ten (10) consecutive trading days. The conversion ratio is two (2) shares of common stock per share of Class “B” Preferred Stock.

The Class “B” Preferred Stock Series 2 is 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 $3.00 for ten (10) consecutive trading days. The conversion ratio is two (2) shares of common stock per share of Class “B” Preferred Stock.

The Class “B” Preferred Stock Series 3 is 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 $4.00 for ten (10) consecutive trading days. The conversion ratio is two (2) shares of common stock per share of Class “B” Preferred Stock.

The preferential amount payable with respect to shares of any of the above 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 17 – EARNINGS PER SHARE

The table below sets forth the computation of basic and diluted net income (loss) per share for the three and nine months ended September 30, 2011 and 2010.

	For the quarter ended September 30						For the nine months ended September 30
	2011			2010			2011			2010
Numerator:
Basic net income (loss)	$	(401,289	)	$	(51,088	)	$	(450,281	)	$	78,779
Diluted net income (loss)	$	(401,289	)	$	(51,088	)	$	(450,281	)	$	78,779

Denominator:
Basic and diluted weighted average common shares outstanding		117,505,341			93,760,579			112,099,157			93,672,181
Basic and diluted net income (loss) per share	$	0.00		$	(0.00	)	$	(0.01	)	$	0.00

As of September 30, 2011, Adino had 122,910,232 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 September 30, 2010, Adino had 1,000,000 earned options outstanding to employees and consultants, exercisable between $0.10 to $0.35 each. At September 30, 2011, the Company had 500,000 options outstanding to consultants, exercisable between $0.15 and $0.35 each. See Note 16 for a discussion of the 500,000 options forfeited during September, 2011. Using an average share price for the nine months ended September 30, 2011 and 2010 of $0.028 and $0.017 respectively, the options resulted in no additional dilution to the Company.

The Company calculated the dilutive effect of the convertibility of the Asher notes, resulting in additional weighted average share additions of 3,316,557 and 3,120,696 for the three and nine months ended September 30, 2011. The effect on earnings per share from the Company’s BWME and Schwartz convertible notes was excluded from the diluted weighted average shares outstanding because the conversion of these instruments would have been non-dilutive since the strike price is above the market price for our stock. There were no dilutive note instruments in place at September 30, 2010.

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 18 – 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 nine months ended September 30, 2011 and 2010.

	Quarter Ended					Quarter Ended					Nine Months Ended					Nine Months Ended
	September 30, 2011		%			September 30, 2010		%			September 30, 2011		%			September 30, 2010		%

Customer A	$	-		0	%	$	-		0	%	$	-		0	%	$	13,402		1	%

Customer B	$	456,000		100	%	$	366,000		100	%	$	1,418,000		100	%	$	1,020,000		69	%

Customer C	$	-		0	%	$	-		0	%	$	-		0	%	$	142,642		10	%

Customer D	$	-		0	%	$	-		0	%	$	-		0	%	$	61,110		4	%

Customer E	$	-		0	%	$	0		0	%	$	-		0	%	$	251,042		17	%

The Company had no outstanding customer receivables at September 30, 2011 or December 31, 2010. Receivables of $37,028 were for accrued oil sales revenue, delivered in the third quarter and uncollected as of September 30, 2011.

NOTE 19 – 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, separately, 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, hiring of employees and the well workover program. The net income of the combined oil and gas segment for the quarter and nine months ended September 30, 2011 and 2010 is as follows:

	Three months ended						Nine months ended
	Sept 30			Sept 30			Sept 30			Sept 30
	2011			2010			2011			2010

Revenues	$	137,123		$	23,020		$	258,581		$	23,020

Production and lease operating expenses		129,961			53,327			312,023			53,327

Revenue sharing royalties		16,264			2,133			36,907			2,133

Impairment of oil and natural gas properties		-			-			-			-

Accretion of asset retirement obligation		1,073			-			2,806			-

Depreciation, depletion and amortization		18,877			13,048			64,256			13,048

Total costs		166,175			68,508			415,992		`
											-
Pretax income (loss) from producing activities		(29,052	)		(45,488	)		(157,411	)		(45,488	)

Income tax expense		-						-			-

Results of oil and natural gas producing activities											-

(excluding overhead and interest costs)	$	(29,052	)	$	(45,488	)	$	(157,411	)	$	(45,488	)

The Company experienced a significant increase in oil revenues during the second quarter of 2011, primarily due to the completion of three wells on the James Leonard lease.

Assets

Total Company assets at September 30, 2011 and December 31, 2010 were $3,563,199 and $3,738,767, respectively. The oil and gas acquisition substantially added to the Company’s asset base. At September 30, 2011 and December 31, 2010, total net oil and gas assets were $566,372 and $719,950 or 16% and 19.3% of the totals, respectively.

As of March 31, 2011, the Company sold Adino Drilling, LLC, resulting in a decrease in machinery and equipment of $350,702, net of depreciation.

	September 30, 2011		December 31, 2010

Machinery and equipment, net of depreciation	$	159,051	$	505,611
Leasehold improvements, net of depreciation		6,779		-
Oil and gas properties: proved, net of depletion and impairment		355,353		119,458
Oil and gas properties: unproved		3,990		59,060
Asset retirement cost		39,490		35,821
Total net oil and gas assets	$	564,663	$	719,950

NOTE 20 – SUBSEQUENT EVENTS

On October 1, 2011, the Company’s Chief Executive Officer, serving as interim president of Adino Exploration, LLC, resigned and the Company’s Chief Financial Officer, Shannon W. McAdams, was named President of Adino Exploration, LLC.

On October 12, 2011, the Company signed a letter of intent with Ashton Oilfield Services, LLC for purchase of oilfield equipment, including a drilling rig, associated equipment and several vehicles. The proposed purchase price for the assets was a total commitment of $6 million ($6,000,000) payable in convertible preferred stock of the Company, with a conversion price of $0.15 per share of common stock of the Company. The letter of intent expires on December 11, 2011.

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

There were no additional subsequent events through November 14, 2011, the date the financial statements were issued.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion should be read in conjunction with our unaudited consolidated interim financial statements and related notes thereto included in this quarterly report and in our audited consolidated financial statements and Management's Discussion and Analysis of Financial Condition and Results of Operations ("MD&A") contained in our Form 10-K for the year ended December 31, 2010. Certain statements in the following MD&A are forward looking statements. Words such as "expects", "anticipates", "estimates" and similar expressions are intended to identify forward looking statements. Such statements are subject to risks and uncertainties that could cause actual results to differ materially from those projected.

RECENT DEVELOPMENTS

Oil and Gas Exploration and Production

Since the Petro Energy 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.

On March 31, 2011, the Company sold the membership shares of Adino Drilling, LLC to a related party. Under the terms of the agreement, the Company realized a reduction in accrued liability of $100,000 and acquired a $500,000 six year, 5.24% interest note receivable, for a total sale price of $600,000. The sale resulted in a gain to the Company of $247,376; however, the transaction’s related party note of $500,000 is not allowed for reporting purposes, therefore the Company realized a reportable loss of $252,624. Adino’s management believes that the sale of the drilling rig and associated equipment was in the best interest of the Company and the shareholders. The rig held by the Company was primarily suited for drilling up to 3,500 feet. However, the Company is currently drilling shallower wells. This large rig would be uneconomical for drilling smaller wells. As a result, the Company has decided to contract with service companies that specialize in shallower wells, thus reducing drilling expense. In addition, the cash flow to be realized from the $500,000 note, accompanied by the decreased related party compensation of $100,000, is expected to increase Adino’s cash flow.

During the second quarter of 2011, the Company realized its first significant revenue from its exploration and production operations. The three wells drilled on the Leonard lease have produced as expected and are delivering consistent revenues.

The Company believes that with development of mature oily assets, additional lease acquisition and new well drilling, its new emphasis on oil and gas exploration will continue to yield successful results.

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 the three and nine months ended September 30, 2011, IFL provided 77% and 85% of the Company’s revenue.

RESULTS OF OPERATIONS

Revenue: The Company’s revenues were $456,000 and $366,817 for the three months ended September 30, 2011 and 2010, respectively, and $1,418,000 and $1,488,483 for the nine months ended September 30, 2011 and 2010, respectively. The Company’s main revenue source was its wholly owned subsidiary, IFL. IFL had multiple customers during the first quarter 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 terminal operations revenue since the May 2010 contract signing.

The Company’s acquisition of the oil and gas leases during July, 2010 and the subsequent drilling operations contributed $30,203 in revenue during the first quarter of 2011, $91,255 during the second quarter of 2011, and $137,123 for total oil revenues of $258,581 for the year. The increase in revenue after the first quarter is largely due to the completion of three oil wells on the James Leonard lease in Coleman County, Texas. Oil revenue for the quarter and nine months ended September 30, 2010 was $23,202.

Cost of Product Sales: Amounts reflected included two different product sale costs: additive expense and royalty expense.

Additive expense: 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 did not require that IFL provide additive services. Additive expense for the nine months ended September 30, 2010 was $234,607. There was no corresponding expense for 2011.

Royalty expense: Production royalty payments began in July 2010 with the acquisition of the PetroGreen companies. Royalty expense for the three and nine months ended September 30, 2011 was $16,264 and $36,907. Expense for the same periods in 2010 was $4,935.

Payroll and Related Expenses: With the addition of Adino Exploration on July 1, 2010, the Company hired several employees to operate its leases. Additionally, the Company has added payroll for one employee at its corporate office. These employee additions result in payroll expense of $46,541 and $5,613 and $158,602 and $5,613 for the three and nine months ended September 30, 2011 and 2010, respectively.

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 for the three and nine months ended September 30, 2011 was $101,490 and $302,070, relatively consistent with the expense incurred during the same periods in 2010 of $100,090 and $300,070. Management evaluates the contract annually.

General and Administrative: The Company’s expense for the quarter and nine months ended September 30, 2011 was $212,293 and $561,425 compared to $197,117 and $515,745 for the same periods in 2010. General and administrative expense is primarily rent expense paid on the IFL terminal to Lone Star, currently $31,855 per month. 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 and administrative expense of $48,440, $20,635 in taxes and $24,815 in insurance expenses for the nine months ended September 30, 2011.

Legal and Professional: Legal and professional expense was $133,220 and $62,828 for the quarters ended September 30, 2011 and 2010, respectively. Expense for the nine months ended September 30, 2011 and 2010 was $324,447 and $177,825, respectively. The nine month increase of $146,622 or 82% is primarily due to increased legal expense related to the lawsuit involving G J Capital.

Consulting Expense: The Company’s consulting expenses were $443,511 and $242,749 for the quarters ended September 30, 2011 and 2010, respectively, an increase of $200,762 or 82%. Consulting expense was $870,479 and $558,680 for the nine months ended September 30, 2011 and 2010, respectively. The nine month increase of $311,799 or 56% is partially due to engineering and geological reports and for operations management for the oil and gas operations. Additionally, the Company granted stock compensation to the directors, controller and a consulting firm during the third quarter of 2011 for expense of $242,107. See Note 16 for a more thorough discussion of the stock compensation expense.

Depreciation Expense: This category includes depreciation, accretion and depletion of the Company’s assets. Total expense was $22,718 and $17,465 for the quarters ended September 30, 2011 and 2010 and $67,119 and $22,550 for the nine months ended September 30, 2011 and 2010, respectively. The increase is due to the addition of machinery and equipment through the Petro Energy acquisition and $2,806 in asset retirement accretion. The Company has also seen a significant increase in its depletion expense, as production increases. Depletion expense for the nine months ended September 30, 2011 was $36,741. There was no corresponding expense for 2010. See Notes 9 and 10 of the Company’s financial statements for additional information regarding these assets and the corresponding depreciation and depletion.

Operating Supplies: Supplies expense was $20,322 and $19,961 for the nine months ended September 30, 2011 and 2010. The Company’s supplies expense related to its oil lease work over and water flood projects in Coleman, Texas.

Interest Income: Interest income remained relatively consistent at $46,898 and $49,386 for the nine months ended September 30, 2011 and 2010, respectively. The Company had agreed to an amendment on the $750,000 note receivable with Mr. Sundlun. This amendment extended the maturity date of the note to August 2011 at no additional interest past the original maturity date of November 6, 2008. Due to the lack of interest expense, the Company recognized a discount on the note and amortizes that discount through the note’s maturity date. The note was not extended prior to the September 30, 2011 report date and is currently being negotiated.

Interest Expense: Interest expense was $75,707 and $49,317 for the three months and $212,569 and $129,789 for the nine months ended September 30, 2011 and 2010, respectively, a nine month increase of $82,780 or 64%. During the third quarter of 2010, the Company closed two separate financings, each resulting in 8% annual interest to the Company. The Company closed additional financing with the Schwartz group in January 2011 at an annual interest rate of 6%. The Company’s derivatives’ discount amortization and debt conversions with Asher Enterprises contributed $53,398 of the increase. Interest expense consistent between 2010 and 2011 are for the notes to Mr. Sundlun and vehicle financing. See Note 13 of the Company’s financial statements for additional information regarding this interest expense

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 4 above for more information regarding these transactions.

Gain (Loss) on Derivative: The Company entered into a series of promissory notes that permit 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 three other financial instruments held by the Company to be considered derivatives. The Company has calculated the change in value of those instruments for the quarter and nine months ended September 30, 2011 for a gain of $35,419 and $28,144, respectively. Loss on derivatives at September 30, 2010 was $76,314. See Note 15 of the Company’s financial statements for a more thorough discussion of this loss.

Gain / Loss 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. On December 31, 2010, the clawback was valued at $337,354 and was revalued at September 30, 2011 at $402,733, resulting in a loss on change in clawback valuation of $64,683 for the quarter ended September 30, 2011 and a net loss on change in fair value of $65,379 for the nine months ended September 30, 2011. The Company recorded a gain on clawback valuation of $114,815 at September 30, 2010.

Net Income/Loss: The Company had net loss of $401,289 and $162,913 for the quarters ended September 30, 2011 and 2010, respectively. Year to date resulted in net loss of $851,570 and $84,134 for the nine months ended September 30, 2011 and 2010, respectively. The increased year to date loss is due to higher legal and consulting expenses, as well as increased payroll and depreciation expenses for the Company’s oil and gas subsidiaries. The Company also sold its wholly owned subsidiary, Adino Drilling, LLC, to a related party on March 31, 2011, resulting in a loss from discontinued operations of $272,042, as the note receivable of $500,000 was disallowed for reporting purposes. See Note 6 for a more thorough discussion of the sale.

CAPITAL RESOURCES AND LIQUIDITY

As of September 30, 2011, our cash and cash equivalents were $176,856, compared to $285,171(including $2,899 from discontinued operations) at December 31, 2010. The Company’s liquidity decreased due to increased legal and consulting expenses.

In order to provide additional financing to drill and complete the wells on the leases that we acquired in the Petro Energy transaction, we issued several convertible promissory notes to a group of investors for an aggregate amount of $272,500 in January 2011. These notes bear interest at the annual rate of 6% and are convertible into Adino common stock at the rate of $0.35 per share. Additionally, the Company took on four additional short-term convertible notes with Asher Enterprises, Inc. during the second and third quarters of 2011.

Cash flow has been an ongoing concern for the Company due to the large amount of legacy liabilities that Adino accumulated during previous years. These liabilities will likely continue to be a drag on the Company’s financial statements unless and until Adino obtains financing or cash flow from operations increases sufficiently, allowing us to pay off these liabilities.

For the nine months ended September 30, 2011, cash used by operating activities was $229,061 compared to cash used by operating activities of $361,128 for the nine months ended September 30, 2010.

The Company incurred capital expenditures of $277,185 in the nine months ended September 30, 2011 to develop its recently acquired oil and gas leases. We were able to secure debt financing at reasonable rates for these expenditures. The Company foresees additional capital expenditures of $375,000 over the next twelve months in order to develop these properties. We do not know at this time whether we will be able to secure financing for these expenditures, and if so, the rates and terms applicable to this financing may exceed our current financing rates.

RISK FACTORS

The market price of the Company's common stock has fluctuated significantly since it began to be publicly traded and may continue to be highly volatile. Factors such as the ability of the Company to achieve development goals, the ability of the Company to compete in the petroleum distribution industry and the oil and gas exploration and production business, the ability of the Company to raise additional funds, general market conditions and other factors affecting the Company's business that are beyond the Company's control may cause significant fluctuations in the market price of the Company's common stock. Such market fluctuations could adversely affect the market price for the Company's common stock.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

As a smaller reporting company, we are not required to provide the information required by this Item.

ITEM 4. CONTROLS 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 ineffective at ensuring 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. We performed additional analysis and other post-closing procedures in an effort to ensure our consolidated financial statements included in this quarterly 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.

Changes in internal controls. There have not been any changes in our internal control over financial reporting that occurred during the quarter ended September 30, 2011 that have materially affected or are reasonably likely to materially affect internal control over financial reporting.

PART II

ITEM 1. LEGAL PROCEEDINGS

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

On March 15, 2010, G J Capital, Ltd. (“G J Capital”) filed suit against Adino Energy Corporation and 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.

In May 2011, the Company’s claims against CapNet, Ritz, Gulf Coast, and Groat were severed from the G J Capital case. These claims will therefore be tried separately; however, the Company is planning to seek reconsideration of this severance.

The G J Capital case was set for trial in September 2011 but was not reached on the court’s docket. A new trial date has not been set. The Company maintains the original contract amount of $275,000 as a liability, but disputes G J Capital’s allegations in the lawsuit.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

On August 9, 2011, the Company entered issued ten million, seven hundred fifty thousand (10,750,000) shares of restricted common stock to a consulting and investor relations firm.

On September 16, 2011, the Company issued 250,000 shares of restricted common stock to each of its directors as compensation for 2011 directors’ fees.

The Company claims an exemption from registration for the above issuances pursuant to Section 4(2) of the Securities Act due to the small number of purchasers and their sophistication in financial and business matters.

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

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. REMOVED AND RESERVED

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

The following documents are filed or furnished as part of this report:

Exhibit
Number		Exhibit

3.1		Articles of Incorporation (as amended January 30, 2008) (incorporated by reference to our Form 10-K filed on March 18, 2009)
3.2		By-laws of Golden Maple Mining and Leaching Company, Inc. (now Adino Energy Corporation) (incorporated by reference to our Form 10-K filed on March 18, 2009)
10.1		Terminaling Services Agreement for Commingled Products (incorporated by reference to our Form 10-Q filed on November 22, 2010)
10.2		Amendment to Terminaling Agreement (incorporated by reference to our Form 10-Q filed on November 22, 2010)
10.3		Resolution of the Board of Directors of December 30, 2009 (incorporated by reference to our Form 10-Q filed on November 10, 2009)
10.4		Membership Interest Purchase Agreement (incorporated by reference to our Form 10-K filed on April 1, 2011)
10.5		Post-Closing Agreement (incorporated by reference to our Form 10-K filed on April 1, 2011)
10.6		Employment agreement of Sonny Wooley
10.7		Employment agreement of Timothy G. Byrd, Sr.
14		Code of Business Conduct and Ethics (incorporated by reference to our Form 10-K filed on March 18, 2009)
31.1		Certification of Chief Executive Officer pursuant to Rule 15d-14(a) of the Exchange Act
31.2		Certification of Chief Financial Officer pursuant to Rule 15d-14(a) of the Exchange Act
32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101		Interactive Data File

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the undersigned has duly caused this Form 10-Q to be signed on its behalf by the undersigned thereunto duly authorized.

	ADINO ENERGY CORPORATION

By:	/s/ Timothy G. Byrd, Sr.
	Timothy G. Byrd, Sr.
	Chief Executive Officer and Director
	November 14, 2011

/s/ Shannon W. McAdams
Shannon W. McAdams
Chief Financial Officer

November 14, 2011

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