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

OR

[  ]  TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE EXCHANGE ACT

For the transition period from

 __________to __________

                                  Commission File No.     000-06404                                 

GATEWAY ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

1415 Louisiana Street, Suite 4100

Houston, TX  77002

(Address of principal executive offices)

(713) 336-0844

(Registrant's telephone number)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the past 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.                 Yes   X          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. (Check one):

Indicate by checkmark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.)  Yes______ No   X  

As of November 14, 2011, the registrant had 23,674,602 shares of its common stock outstanding.

GATEWAY ENERGY CORPORATION AND SUBSIDIARIES

INDEX TO QUARTERLY REPORT

ON FORM 10-Q

Part  I – Financial Information

ITEM 1.     FINANCIAL STATEMENTS

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

GATEWAY ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

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

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

Business and Organization

Gateway Energy Corporation (the “Company,” or “Gateway,”), a Delaware corporation, was incorporated in 1960 and entered its current business in 1992.  The Company's common stock is traded in the over-the-counter market on the bulletin board (“OTCBB”) section under the symbol GNRG.  Gateway is engaged in the midstream natural gas business.  The Company owns and operates natural gas distribution, transmission and gathering systems located onshore in the continental United States and offshore in federal and state waters of the Gulf of Mexico.

Gateway conducts all of its business through its wholly owned subsidiary companies, Gateway Pipeline Company, Gateway Offshore Pipeline Company, Gateway Energy Marketing Company, Gateway Processing Company, Gateway Pipeline USA Corporation, Gateway Delmar LLC and CEU TX NPI, LLC.  Gateway-Madisonville Pipeline, L.L.C, previously known as Gateway-ADAC Pipeline, L.L.C., is 67% owned by Gateway Pipeline Company and 33% owned by Gateway Processing Company.   Access to the Company’s annual reports on Form 10-K, quarterly reports on Form 10-Q, the Company’s Code of Ethics, and current reports on Form 8-K are available at the Company’s website, www.gatewayenergy.com.

                At the Annual Meeting of Stockholders of the Company held on May 26, 2011, the Company’s stockholders approved an amendment to the Company’s Restated Certificate of Incorporation, as amended, to (a) increase the authorized number of shares of the Company’s common stock from 35,000,000 to 150,000,000 and (b) reduce the par value of the Company’s common stock from $0.25 per share to $0.01 per share. The increase in the number of authorized shares of the Company’s common stock and the reduction in the par value of the Company’s common stock was effected pursuant to a Certificate of Amendment of Restated Certificate of Incorporation of the Company on June 1, 2011 and was effective as of such date.  The Company has reflected this change in its capital structure for all periods presented.  

                Basis of Presentation

                The Company has prepared the accompanying unaudited consolidated financial statements in accordance with U. S. generally accepted accounting principles ("GAAP") for interim financial information and pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) instructions to Form 10-Q and Item 310(b) of regulation S-K.  These financial statements should be read together with the financial statements and notes in the Company’s 2010 Form 10-K filed with the SEC on March 18, 2011.  Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted.  The accompanying financial statements reflect all adjustments and disclosures, which, in the Company’s opinion, are necessary for fair presentation.  All such adjustments are of a normal recurring nature.  The results of operations for the interim periods are not necessarily indicative of the results of the entire year.  Certain reclassifications have been made to the prior year’s financial statements to conform to the current period’s presentation.

                All of the Company’s operations are onshore in the continental United States and offshore in federal and state waters of the Gulf of Mexico.  Management separately reviews and evaluates the operations of each of its gas distribution, transmission and gathering systems individually, however these operations are aggregated into one reportable segment due to the fact that all of the Company’s operations are subject to similar economic and regulatory conditions and operate in the same industry group such that they are likely to have similar long-term prospects for financial performance.

                Glossary

                In the following discussion, “Mcf” refers to thousand cubic feet of natural gas; “Bbl” refers to barrel of liquid hydrocarbons of approximately 42 U.S. gallons; “Btu” refers to British thermal unit, a common measure of the energy content of natural gas; “MMBtu” refers to one million British thermal units; “Mcfe” refers to thousand cubic feet equivalent; and liquid hydrocarbons are converted to Mcf equivalents using the ratio of 1.0 barrel of liquid hydrocarbons to 6.0 Mcf of natural gas.

                Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Management’s significant estimates include depreciation of long-lived assets, estimates and timing of asset retirement obligations, amortization of deferred loan costs, deferred tax valuation allowance, valuation of assumed liabilities, intangible lives, impairment and valuation of the fair value of long-lived assets, purchase price allocations and valuation of stock based transactions.  Actual results could differ from those estimates.

                Revenue Recognition

Revenues from the sales of natural gas are generated under purchase and sales contracts that are priced at the beginning of the month based upon established gas indices.  The Company purchases and sells the gas using the same index to minimize commodity price risk.  Revenues from the sales of natural gas are recognized at the redelivery point, which is the point at which title to the natural gas transfers to the purchaser.  Transportation revenues are generated under contracts which have a stated fee per unit of production (Mcf, MMBtu, or Bbl) gathered or transported and are recognized at the point such revenues are earned pursuant to the terms of the applicable transportation contract, which can vary.

                Property and Equipment

Property and equipment is stated at cost, plus capitalized interest costs on major projects during their construction period.  Additions and improvements that add to the productive capacity or extend the useful life of an asset are capitalized.  Expenditures for maintenance and repairs are charged to expense as incurred.  Depreciation and amortization is calculated using the straight-line method over estimated useful lives ranging from 10 to 20 years for its gas distribution, transmission and gathering systems and from two to ten years for office furniture and other equipment.  Upon disposition or retirement of any gas distribution, transmission or gathering system components, any gain or loss is charged or credited to accumulated depreciation.  When entire gas distribution, transmission and gathering systems or other property and equipment are retired or sold, any resulting gain or loss is credited to or charged against operations.

For the three and nine months ended September 30, 2011, depreciation, depletion and amortization expense was $163,431 and $501,497, respectively, as compared to $181,188 and $547,477 for the three and nine months ended September 30, 2010, respectively.  Property, plant and equipment and identifiable intangible assets are reviewed for impairment, in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 360, “Property, Plant, and Equipment,” whenever events or changes in circumstances indicate that the carrying amount may not be recoverable.  If the sum of the expected undiscounted cash flows is less than the carrying value of the related asset or group of assets, a loss is recognized for the difference between the fair value and carrying value of the asset or group of assets.  

During the third quarter of 2011, the Company was notified by the operator of a platform utilizing one of the Company’s offshore systems of its intent to abandon its lease in 2012.  As a result of this notification and continuing conversations with its customers, the Company determined that it was more likely than not that the useful lives of all their offshore systems were one and one-half to ten years shorter than last evaluated, and that the Company had a legal obligation to pay for the abandonment of its systems.  As a result, the Company performed an impairment review of its capitalized costs on these systems, including their future abandonment costs and associated intangible assets, in accordance with Topic 360. 

Furthermore, in connection with the aforementioned impairment analysis conducted with its offshore systems, the Company determined that further impairment analysis was necessary for its Madisonville pipeline system due to the lack of production from the wells connected to the system since May 2011 and no materialization of potential alternative uses for the pipeline. In the fourth quarter of 2010, the Company had determined that an impairment was necessary for its Madisonville pipeline system at that time due to the continual depletion of reserves in 2010, the near breakeven to below operating margin in the fourth quarter of 2010 and the lack of activity by the producer to recomplete or perform previously announced workovers to increase volume output.

To determine the fair value of these assets, the Company estimated the future cash flows from these systems based on the likelihood of various outcomes using a probability weighted approach. As a result, it was determined that impairments totaling $3,365,168 were required.  These impairments were apportioned as $3,236,156 to the carrying value of the Company’s property and equipment and $129,012 to the carrying value of the Company’s intangible assets.

ASC Topic 820, “Fair Value Measurements” establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. The impairments noted above were based on Level 3, unobservable inputs, including conversations with the Company’s customers concerning future plans for the fields supporting the Company’s gathering systems, the Company’s estimates of the cost to abandon the systems and the Company’s discounted cash flow analysis.

Due to the offsetting nature of (i) the aforementioned change in useful lives of some of the Company’s gas distribution, transmission and gathering systems, (ii) the increase in the Company’s required asset retirement obligation discussed below and (iii) the current period impairment expense, the Company’s future depreciation expense will not be materially different in future periods.

Asset Retirement Obligations

 The Company recognizes asset retirement obligations associated with the retirement of tangible long-lived assets that result from their acquisition, construction, development and operation, when laws or regulations require the Company to pay for their abandonment, in accordance with ASC Topic 410, "Asset Retirement and Environmental Obligations". The Company records the fair value of an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying value of the related long-lived asset. The obligation is subsequently allocated to expense using a systematic and rational method. The Company has recorded an asset retirement obligation to reflect its legal obligations related to future abandonment of its pipelines and gas gathering systems, even though the timing and realized allocation of the cost between the Company and its customers may be subject to change. The Company estimates the expected cash flows associated with the legal obligation and discounts the amount using a credit-adjusted, risk-free interest rate. At least annually, the Company reassesses the obligation to determine whether a change in the estimated obligation is necessary. The Company also evaluates whether there are indicators that suggest the estimated cash flows underlying the obligation have materially changed. Should those indicators suggest the estimated obligation may have materially changed on an interim basis (quarterly), the Company will accordingly update its assessment.  

At the date of acquisition of certain offshore pipeline and gas gathering systems, and in periods subsequent thereto, the Company determined that no asset retirement obligation was required to be recognized.  As a result of the Company determining that the useful lives of its offshore systems were shorter than originally anticipated, and as part of the impairment analysis noted above, the Company was required to reevaluate its assumptions concerning the fair value of its asset retirement obligation.  In this process, the Company determined that not considering the future abandonment liability at the date of acquisition of its gas distribution, transmission and gathering systems constituted an accounting error; however, the impact on its current and prior periods’ financial statements is immaterial based on the guidance provided by SAB Topics 1M and 1N. Therefore, the Company did not restate its prior period results.

As of September 30, 2011, the Company has established an estimated asset retirement obligation of $1,013,279, due to the change in estimate brought about the aforementioned change in the Company’s estimated abandonment dates, ongoing discussions with its customers and updating the costs to retire these assets, and has reflected such in its consolidated balance sheet on that date.  This liability will be accreted to the Company’s total undiscounted estimated liability over future periods until the date of such abandonment.  The Company estimates such accretion expense to total approximately $102,000 on an annual basis.

Concentrations of Credit Risk

                The Company maintains all cash in deposit accounts, which at times may exceed federally insured limits.  Additionally, the Company maintains credit on account for customers. The Company has not experienced material losses in such accounts and believes its accounts are fully collectable.  Accordingly, no allowance for doubtful accounts has been provided.

                During the three months ended September 30, 2011, two companies, Cokinos Energy Corporation  and ETC Marketing, Ltd., supplied 52.6% and 47.4%, respectively, and during the nine months ended September 30, 2011, these two companies, along with Shell Energy North America, supplied 30.3%, 28.9% and 40.8%, respectively, of the total natural gas purchased by the Company during these periods.  During the three and nine months ended September 30, 2010, Shell supplied 100% of the total natural gas purchased by the Company. 

                Due to the nature of the Company’s operations and location of its gas distribution, transmission and gathering systems, the Company is subject to concentration of its sources of revenue from a few significant customers.  Revenues from customers representing 10% or more of total revenue for the three and nine months ended September 30, 2011 and 2010 are as follows:  

The loss of either of our contracts with Dart Container Corporation or Owens Corning, or closure of their plants, could have a material adverse effect on our business, results of operations and financial condition.  The Company’s accounts receivable are not collateralized.  

                Earnings Per Share

Basic earnings per share is computed by dividing net income or loss by the weighted average number of common shares outstanding during the period.  Diluted earnings per share is computed by dividing net income or loss by the weighted average number of shares outstanding, after giving effect to potentially dilutive common share equivalents outstanding during the period.  Potentially dilutive common share equivalents are not included in the computation of diluted earnings per share if they are anti-dilutive.  For the three and nine months ended September 30, 2011 and 2010, all potentially dilutive common shares arising from outstanding stock options and restricted stock have been excluded from diluted earnings per share as their effects were anti-dilutive.  

                Acquisition of Hickory Creek Gathering System

Gateway acquired the Hickory Creek Gathering System (“Hickory Creek”) from Hickory Creek Gathering L.P. and Range Texas Production, LLC on January 7, 2010, for a cash purchase price of $3,737,705, and began consolidating its results on that date.  The transaction was accounted for in accordance with FASB ASC Topic 805 “Business Combinations.”  As the results of Hickory Creek’s operations for the period from January 1, 2010 – January 7, 2010 were not material, the Company has not included them in the pro forma presentation below.  Hickory Creek’s results are included in the Company’s consolidated results for both periods ended September 30, 2011 and 2010.  The Company incurred approximately $43,000 in acquisition costs during the three months ended March 31, 2010, related to due diligence and legal fees associated with evaluating the asset.

Acquisition of Pipeline from Laser Midstream

On September 22, 2010, Gateway entered into an Asset Sales Agreement with Laser Pipeline Company, LP (“Laser”) pursuant to which it agreed to acquire from Laser four pipelines and related assets for $1,100,000 in cash.  The Company paid a $50,000 deposit upon execution of the Agreement. Transfer of ownership occurred and consolidation of the pipelines began on the closing date of October 18, 2010.  The transaction was accounted for in accordance with  ASC Topic 805.  The Company recognized $67,884 and $46,085 in revenue and operating margin, respectively, for the three months ended September 30, 2011, and $223,237 and $167,511 in revenue and operating margin, respectively, for the nine months ended September 30, 2011, from these assets.

                Acquisition of Pipeline from American Midstream

On September 24, 2011, the Company completed the acquisition of a natural gas pipeline from American Midstream Partners, L.P. (“American Midstream”) for a purchase price of $50,000.  The pipeline delivers natural gas into a plant owned by Owens Corning in Delmar, New York.  In connection with the closing of the acquisition, the Company entered into a new long-term contract with Owens Corning to transport natural gas at a fixed monthly rate.  As the results of this pipeline’s operations for the period from January 1, 2010 – September 30, 2010 were not material, the Company has not included them in the pro forma presentation below.   

                Pro Forma Results of Operations

                The following unaudited pro forma consolidated results of operations for the three and nine months ended September 30, 2010, are presented as if the Laser acquisition had been made on January 1, 2010.  The operations of the Laser acquisition have been included in the statement of operations since October 18, 2010, the closing date of the acquisition.  The pro forma consolidated results of operations include adjustments to give effect to the effective change in depreciation rates as well as certain other adjustments.

For the Three Months Ended September 30, 2010

For the Nine Months Ended September 30, 2010

(1) The pro forma adjustments include additional operating expenses expected based on Gateway’s pipeline integrity and maintenance plan and additional expenses or modifications to depreciation, insurance, interest, and other related costs.

                The Company’s 2007 Equity Incentive Plan (“2007 Plan”) provides for stock-based compensation for officers, employees and non-employee directors.  The 2007 Plan was approved by shareholders during May 2007 and makes available 2,000,000 shares for award. 

During the nine months ended September 30, 2011, the Company issued 334,471 options to acquire shares of its common stock and 450,330 shares of restricted stock.  During the nine months ended September 30, 2011, the Company had forfeitures of 75,000 unvested stock options and 16,667 shares of unvested restricted stock.  As of September 30, 2011, 622,249 shares of the Company’s common stock were issuable under outstanding stock option grants under the 2007 Plan (which is in addition to 40,000 shares issuable under outstanding stock option grants under the Company’s former 1998 Stock Option Plans).  The Company also has 506,579 shares of unvested restricted stock outstanding under the 2007 Plan.  As of September 30, 2011, there are 627,423 shares available for issuance under future grants of awards under the 2007 Plan.

Total stock-based compensation cost was $31,780 and $20,769 for the three months ended September 30, 2011 and 2010, respectively, and $56,514 and $(9,231) for the nine months ended September 30, 2011 and 2010, respectively.  The Company considers all awards of stock-based compensation as a single award with an expected life equal to the average expected life of component awards and amortizes the fair value of the award over the requisite service period. 

Compensation expense related solely to stock options was $4,474 for the three months ended September 30, 2011, compared to compensation expense of $4,102 for the three months ended September 30, 2010.  There were no forfeiture adjustments recorded in either the three months ended September 30, 2011 or 2010.  For the nine months ended September 30, 2011, compensation expense and forfeiture adjustments were $10,713 and $(2,364), respectively, compared to compensation expense and forfeiture adjustments of $26,392 and $(52,290), respectively, for the nine months ended September 30, 2010.   At September 30, 2011, there was $43,198 of total unrecognized compensation expense related to unvested stock option awards which is expected to be recognized over a remaining weighted-average period of two years.

                The following table represents stock option activity for the nine months ended September 30, 2011:

The market value of the Company’s common stock, as quoted on the OTCBB, on September 30, 2011 was $0.18 per share.

Compensation expense for restricted stock is recognized on a straight-line basis over the vesting period.  The Company recognized $27,307 and $48,165 in compensation expense related to restricted stock grants during the three and nine months ended September 30, 2011, respectively.  The Company recognized $16,667 in compensation expense related to restricted stock grants during the three and nine months ended September 30, 2010.  Compensation expense related to restricted stock grants is based upon the market value of the shares on the date of the grant.  As of September 30, 2011, unrecognized compensation cost related to restricted stock awards was $107,946, which is expected to be recognized over the remaining weighted-average period of two years.

                The following table represents restricted stock activity for the nine months ended September 30, 2011:

                Trade Notes Payable

During 2010, the Company executed premium finance agreements for its insurance premiums.  The total original principal amount of the notes issued in connection with these agreements was $428,367, with an interest rate of 4.95%.  The notes require monthly principal and interest payments.  The amount of the monthly payment varies depending on any changes in coverage and policy renewal periods. As of September 30, 2011, there was $79,711 outstanding under these notes.

                Revolving Credit Facility

On December 7, 2009, the Company entered into a Credit Agreement (the “Agreement”) with Meridian Bank Texas (“Meridian”), regarding a revolving credit facility.  The original borrowing base under the Agreement had been established at $3.0 million, which may be increased at the discretion of Meridian to an amount not to exceed $6.0 million.  The credit facility is secured by all of the Company’s assets and had an original term of 39 months maturing on April 30, 2012.  The term was reset to a maturity date of November 30, 2011, in consideration of Meridian refraining to institute a minimum commitment reduction. Meridian and the Company are currently in conversations to extend the maturity back to the original maturity on April 30, 2012, however there is no guarantee such extension will be granted. The credit facility contains financial covenants defining various financial measures, with which the Company is in compliance.  Interest on outstanding balances accrues at The Wall Street Journal prime rate, plus one and one-half percent, with a minimum rate of 5.50% and is payable monthly.  The principal is due upon maturity.  Unused borrowing base fees are 0.50% per year of the average for the period of calculation of an amount determined daily equal to the difference between the borrowing base and the aggregate outstanding principal balance of the facility.  This amount is paid quarterly.

As of September 30, 2011, there was a $2,550,000 outstanding balance on the facility.

From time to time the Company is involved in litigation concerning its properties and operations.  There is no known or pending litigation expected to have a material effect on the Company’s financial statements.

The carrying amount of cash and cash equivalents, trade receivables, trade payables and short-term borrowings approximate fair value because of the short maturity of those instruments.  The carrying amount of the Company’s revolving credit facility approximates fair value because of its variable interest rate.  The fair value of the Company’s financial instruments is based upon current borrowing rates available for financings with similar terms and maturities, and is not representative of the amount that could be settled, nor does the fair value amount consider the tax consequences, if any, of settlement.

Item  2.   Management's Discussion and Analysis of Financial Condition and Results of Operations

This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that relate to possible future events, our future performance, and our future operations. In some cases, you can identify these forward-looking statements by the use of words such as “may,” “will,” “should,” “anticipates,” “believes,” “expects,” “plans,” “future,” “intends,” “could,” “estimate,” “predict,” “potential,” “continue,” or the negative of these terms or other similar expressions. These statements are only our predictions.  Our actual results could and likely will differ materially from these forward-looking statements for many reasons, including the risks described in our Annual Report on Form 10-K for the year ended December 31, 2010, and our quarterly reports on Form 10-Q.  We cannot guarantee future results, levels of activities, performance, or achievements. We undertake no duty to update any of the forward-looking statements after the date of this document to conform them to actual results or to changes in our expectations.

                Critical Accounting Policies

A summary of the significant accounting policies consistently applied in the preparation of the accompanying consolidated financial statements follows.

                Use of Estimates

                The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Management’s significant estimates include depreciation of long-lived assets, estimates and timing of asset retirement obligations, amortization of deferred loan costs, deferred tax valuation allowance, valuation of assumed liabilities, intangible lives, impairment and valuation of the fair value of long-lived assets, purchase price allocations and valuation of stock based transactions.  Actual results could differ from those estimates.

                Revenue Recognition Policy

Revenues from the sales of natural gas are generated under purchase and sales contracts that are priced at the beginning of the month based upon established gas indices.  We purchase and sell the gas using the same index to minimize commodity price risk.  Revenues from the sales of natural gas are recognized at the redelivery point, which is the point at which title to the natural gas transfers to the purchaser.  Transportation revenues are generated under contracts which have a stated fee per unit of production (Mcf, MMBtu, or Bbl) gathered or transported and are recognized at the point such revenues are earned pursuant to the terms of the applicable transportation contract, which can vary.

Property and Equipment

Property and equipment is stated at cost, plus capitalized interest costs on major projects during their construction period.  Additions and improvements that add to the productive capacity or extend the useful life of an asset are capitalized.  Expenditures for maintenance and repairs are charged to expense as incurred.  Depreciation and amortization is calculated using the straight-line method over estimated useful lives ranging from 10 to 20 years for its gas distribution, transmission and gathering systems and from two to ten years for office furniture and other equipment.  Upon disposition or retirement of any gas distribution, transmission or gathering system components, any gain or loss is charged or credited to accumulated depreciation.  When entire gas distribution, transmission and gathering systems or other property and equipment are retired or sold, any resulting gain or loss is credited to or charged against operations.

Asset Retirement Obligations

 We recognize asset retirement obligations associated with the retirement of tangible long-lived assets that result from their acquisition, construction, development and operation, when laws or regulations require us to pay for their abandonment, in accordance with ASC Topic 410, “Asset Retirement and Environmental Obligations”. We record the fair value of an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying value of the related long-lived asset. The obligation is subsequently allocated to expense using a systematic and rational method. We have recorded an asset retirement obligation to reflect our legal obligations related to future abandonment of our pipelines and gas gathering systems, even though the timing and realized allocation of the cost between the Company and our customers may be subject to change. We estimate the expected cash flows associated with the legal obligation and discount the amount using a credit-adjusted, risk-free interest rate. At least annually, we reassesses the obligation to determine whether a change in the estimated

                Results for the three and nine months ended September 30, 2011 and 2010        

                Revenues 

Our total revenues were $1,806,602 for the three months ended September 30, 2011, which were relatively flat with the $1,804,317 of total revenues we recognized for the three months ended September 30, 2010.  During the three months ended September 30, 2011, sales revenues on our Waxahachie distribution system increased by $24,022 compared to the three months ended September 30, 2010. Sales volumes at Waxahachie increased slightly to 2,903 MMBtu/d while sales prices averaged $4.86 per MMBtu in each period. During the three months ended September 30, 2011, our transportation revenues decreased by $42,117 as compared to the same period of the prior year.  Revenues of $67,884 from our newly acquired Laser operations for the three months ended September 30, 2011, were offset by net decreases of $110,001 attributable to production declines on natural gas wells connected to our gathering systems.  We believe that transportation revenues will eventually increase on some of our gathering systems due to new drilling and workover activities, but doubt meaningful activities will

15

                Operating Margin

Operating margin, which we define as fee revenues from the transportation of natural gas, plus revenues from the sale of natural gas net of the cost of purchased gas, less operating and maintenance expenses and reimbursable costs generated by our pipeline systems, was $475,868 for the three months ended September 30, 2011, which represented an increase of $14,532 from the $461,336 of operating margin we recognized for the three months ended September 30, 2010.  Our newly acquired natural gas distribution operations from Laser contributed $46,085 to operating margin for the current period.  In addition, the Waxahachie distribution system generated a quarter-over-quarter increase of $7,258 in operating margin contribution to $154,116 for the current period. 

Operating margin contribution from the Hickory Creek, Madisonville, and all Gulf of Mexico gathering systems was $275,667 for the three months ended September 30, 2011, which represented a decrease of $38,811 from the prior period.  The decreases in operating margin on these gathering systems were attributable to the aforementioned production declines from gas wells connected to these systems.  Sizable production declines from the wells connected to our Hickory Creek gathering system are typical of newly fractured horizontal wells located in the Barnett Shale.  However, the rate of decline from wells connected to our Hickory Creek gathering system is decreasing over time.  The Madisonville pipeline is currently dormant due to lack of production from the Madisonville Field.  We are evaluating alternative uses for the Madisonville pipeline in the event the Madisonville Field does not resume production.  Production volumes connected to our Gulf of Mexico gathering systems are expected to continue to decline for the remainder of 2011. Customers of some of our gathering systems have also informed us of preliminary plans to drill at least two development wells and perform workovers in 2012.

Operating margin was $1,488,229 for the nine months ended September 30, 2011, which represented a decrease of $4,305 from the $1,492,534 of operating margin we recognized for the nine months ended September 30, 2010.  Our newly acquired natural gas distribution operations from Laser contributed $167,511 to operating margin for this period.  In addition, the Waxahachie distribution system generated a period-over-period increase of $83,667 in operating margin contribution to $487,864 for this current period.  We expect a similar operating margin on the Laser and Waxahachie distribution systems for the fourth quarter of 2011 as for the quarterly average of the first nine months of 2011.  Operating margin contribution from the Hickory Creek, Madisonville and all Gulf of Mexico gathering systems was $832,854 for the nine months ended September 30, 2011, which represented a decrease of $255,483 from the prior period.  The decreases in operating margin on these gathering systems were attributable to the aforementioned production declines from gas wells connected to these systems. 

                Asset Impairments

During the third quarter of 2011, we were notified by the operator of a platform utilizing one of our offshore systems of its intent to abandon its lease in 2012.  As a result of this notification and continuing conversations with our customers, we determined that it was more likely than not that the useful lives of all our offshore systems were one and one-half to ten years shorter than last evaluated, and that we had a legal obligation to pay for the abandonment of our systems.  As a result, we performed an impairment review of our capitalized costs on these systems, including their future abandonment costs and associated intangible assets. 

Furthermore, in connection with the aforementioned impairment analysis conducted with our offshore systems, we determined that further impairment analysis was necessary for our Madisonville pipeline system due to the lack of production from the wells connected to the system since May 2011 and no materialization of potential alternative uses for the pipeline. In the fourth quarter of 2010, we had determined that an impairment was necessary for our Madisonville pipeline system at that

General and Administrative Costs

General and administrative expenses were $329,544 for the three months ended September 30, 2011, which represented a decrease of $43,363 from the $372,907 in such expenses we recognized for the three months ended September 30, 2010.  This decrease was primarily related to lower legal and investor relations expenses.

General and administrative expenses were $1,072,202 for the nine months ended September 30, 2011, which represented a decrease of $108,462 from the $1,180,664 in such expenses we recognized for the nine months ended September 30, 2010.  Across the board decreases were partially offset by a $65,745 increase in stock compensation as a $52,290 reversal was recognized in the second quarter of 2010 due to the forfeiture of unvested options by prior management. We expect general and administrative expenses to remain lower in 2011, relative to the comparable 2010 periods, as we continue to manage our overall level of fixed costs.

                Acquisition Costs

We incurred acquisition related costs of $19,490 and $67,357, respectively, during the three and nine months ended September 30, 2011, primarily related to the acquisition of a pipeline located in Delmar, New York from American Midstream completed on September 24, 2011.

We incurred acquisition related costs of $3,570 and $47,023 during the three and nine months ended September 30, 2010, related to our Hickory Creek acquisition in January 2010.  

Consent Solicitation and Severance Costs

Consent solicitation and severance costs of $7,669 and $1,550,631 for the three and nine months ended September 30, 2010, respectively, were for legal and proxy preparation costs we incurred related to the consent solicitation initiated by our current CEO in 2010 and severance costs associated with the termination of the prior management of the Company at the conclusion of the consent solicitation.

                Other Income (Expense)

Our interest income fluctuates directly with the average amount of cash on deposit.  Our interest expense fluctuates directly with the amount of outstanding insurance notes payable and the amount of borrowings under the Company’s bank revolving credit agreement, and remained relatively constant between the three and nine month periods ended September 30, 2011 and 2010.

Other income, net, for the three and nine months ended September 30, 2011, consisted primarily of reimbursement of prior year base cost plus fees from customers in the Gulf of Mexico.  Other income, net, for the three and nine months ended September 30, 2010 primarily consisted of a true-up of over accrued prior period operating costs and the refund of insurance premiums paid during prior periods.

Liquidity and Capital Resources

Our strategy is to maximize the potential of currently owned properties, to construct new pipeline systems, and to acquire properties that meet our economic performance hurdles.  We are actively exploring our capital needs to allow us to accelerate the implementation of our growth strategy, and any new capital may take several forms.  There is no guarantee that we will be able to raise outside capital.  Without a significant infusion of new capital, we believe we can finance the construction of new facilities and generate new cash flows to the Company, but only at a pace that can be supported by cash flows and existing financing agreements.

We used $108,179 of cash in investing activities during the nine months ended September 30, 2011, including $50,000 to acquire a natural gas pipeline from American Midstream Partners, L.P. (“American Midstream”). We funded the cost of the acquisition from cash on hand. We also spent $58,179 primarily to install a cathodic protection system at our Waxahachie system, which will lengthen the expected life of the system.  During 2010, we used $3,795,233 million of cash in investing activities, primarily for the purchase of our Hickory Creek Gathering System.

 On December 7, 2009, the Company entered into a Credit Agreement (the “Agreement”) with Meridian Bank, Texas (“Meridian”), regarding a revolving credit facility provided by Meridian to the Company.  The original borrowing base under the Agreement had been established at $3.0 million, which may be increased at the discretion of Meridian to an amount not to exceed $6.0 million.   The credit facility is secured by all of the Company’s assets and had an original term of 39 months maturing on April 30, 2012.  The term was reset to a maturity date of November 30, 2011, in consideration of Meridian refraining to institute a minimum commitment reduction. Meridian and the Company are currently in conversations to extend the maturity back to the original maturity on April 30, 2012. We currently expect the Agreement to be extended but cannot assure such extension. The credit facility contains financial covenants defining various financial measures and levels of these measures with which the Company is in compliance.  Interest on outstanding balances accrues at The Wall Street Journal prime rate, plus one and a half percent, with a minimum rate of 5.50% payable monthly.  The principal is due upon maturity.  Unused borrowing base fees are 0.50% per year of the average for the period of calculation of an amount determined daily equal to the difference between the borrowing base and the aggregate outstanding principal balance of the facility.  This amount is paid quarterly.  As of September 30, 2011, there was a $2,550,000 balance on the facility.

                Off-Balance Sheet Arrangements

The Company has no off-balance sheet arrangements at September 30, 2011.

Non-GAAP Financial Measure

We evaluate our operations using operating margin, which we define as revenues less cost of purchased gas, operating and maintenance expenses and reimbursable costs.  Such amounts are before asset impairments, general and administrative expense, depreciation, depletion and amortization expense, interest income or expense or income taxes.  Operating margin is not a GAAP measure but the components of operating margin are computed by using amounts that are determined in accordance with GAAP. A reconciliation of operating margin to net loss, which is its nearest comparable GAAP financial measure, is included in the table below.

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

                Management’s Report on Disclosure Controls and Procedures

                We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our reports filed under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission's rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer (our Principal Executive Officer  and Principal Financial Officer) to allow for timely decisions regarding required disclosure.

                As of September 30, 2011, the end of our quarter covered by this report, we carried out an evaluation, under the supervision and with the participation of our Chief Executive Officer (our Principal Executive Officer and Principal Financial Officer), of the effectiveness of the design and operation of our disclosure controls and procedures. Based on the foregoing, our Chief Executive Officer (our Principal Executive Officer and Principal Financial Officer) concluded that our disclosure controls and procedures were effective as of the end of the period covered by this quarterly report.

                Changes in Internal Control over Financial Reporting

                There have been no changes in our internal controls over financial reporting that occurred during our quarter ended September 30, 2011, that have materially affected or are reasonably likely to materially affect, our internal controls over financial reporting.

Part II – OTHER INFORMATION

Item 1.   Legal Proceedings

                There are no material, existing or pending legal proceedings against our Company or any of our subsidiaries, nor are we or any of our subsidiaries involved as a plaintiff in any material proceeding or pending litigation.  There are no proceedings in which any of our directors, officers or affiliates, or any registered or beneficial shareholder, is an adverse party or has a material interest adverse to our interest.

Item 1A.  Risk Factors

                There are no material changes from the risk factors as previously disclosed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2010.

None

None

Item 4.   (Removed and Reserved)

Item 5.   Other Information

                None

Item 6.   Exhibits 

                31.1*     Section 302 Certification   

                32.1*     Section 906 Certification

                101*       Interactive data files pursuant to Rule 405 of Regulation S-T

* Filed with this Form 10-Q for Gateway Energy Corporation

SIGNATURES

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

                                                                          GATEWAY ENERGY CORPORATION