UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2011

 oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE EXCHANGE ACT OF 1934

Commission File No. 000-6404

Gateway Energy Corporation

(Exact name of registrant as specified in its charter)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes _____   No      X             

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

Note – Checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the Exchange Act from their obligations under those Sections.

Indicated 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 of 1934 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.        X                            

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.

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

Yes _____     No          X     

The aggregate market value of voting and non-voting common equity held by non-affiliates of the registrant computed by reference to the price at which the common equity was sold, or the average bid and asked price of such common equity, as of June 30, 2011, the last business day of the registrant’s most recently completed second fiscal quarter, was $3,613,922.

The number of shares outstanding of the registrant’s common stock, $0.01 par value as of March 29, 2012, was 24,196,970.

DOCUMENTS INCORPORATED BY REFERENCE

The following document is incorporated by reference into the indicated parts of this Annual Report on Form 10-K to the extent specified in such parts:  

Part III of this Annual Report on Form 10-K incorporates by reference information in the Proxy Statement for the 2012 Annual Meeting of Stockholders of Gateway Energy Corporation.

                                                                INDEX

GLOSSARY OF TERMS

The abbreviations, acronyms, and industry terminology in this report are defined as follows:

“Back-to-back purchase and sale contracts”, refers to natural gas purchased and sold based on the same published, monthly index price.

“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

“Mcf” refers to thousand cubic feet of natural gas

“MMBtu” refers to one million British thermal units

FORWARD-LOOKING STATEMENTS

Statements made in this Annual Report on Form 10-K and other reports and proxy statements filed with the Securities and Exchange Commission, communications to shareholders, press releases and oral statements made by representatives of Gateway Energy Corporation contain 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.  Actual results could differ materially from those projected in such forward-looking statements as a result of the risk factors set forth below in the section entitled “Factors Affecting Future Results” and elsewhere in this document.  Therefore, we cannot guarantee future results, levels of activities, performance, or achievements.  We are under 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.

PART I

ITEM 1.  BUSINESS.

Gateway Energy Corporation (the “Company,” “Gateway,” “we,” or “our”), a Delaware corporation, was incorporated in 1960 and entered its current business in 1992.  Gateway’s common stock is traded in the over-the-counter market on the bulletin board section under the symbol “GNRG”.  Our principal executive offices are located at 1415 Louisiana Street, Suite 4100, Houston, Texas 77002 and our telephone number is 713-336-0844.

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, Gateway Commerce LLC and CEU TX NPI, L.L.C.  Gateway-Madisonville Pipeline, L.L.C. is 67% owned by Gateway Pipeline Company and 33% owned by Gateway Processing Company. 

Access to our annual reports on Form 10-K, quarterly reports on Form 10-Q, our Code of Ethics and current reports on Form 8-K are available at Gateway’s website, www.gatewayenergy.com. 

Description of Business

Gateway is engaged in the midstream energy business.  We own and operate natural gas distribution, gathering and transmission pipeline systems located onshore the continental United States and offshore in federal and state waters of the Gulf of Mexico.  For the year ended December 31, 2011, all of our revenue was generated under long-term contracts with either fee-based rates or back to back purchases and sales based on the same published monthly index price. 

Business Growth Strategy

Our primary business objective is to achieve profitable and sustainable growth in the midstream energy business. We intend to achieve this objective by executing the following business strategies:

·         Expanding our unregulated natural gas distribution activities. We seek to increase the stability of our cash flow by expanding our natural gas distribution activities.  Since October 2010, we have added six new pipelines to our core Waxahachie system, all of which serve industrial end users of natural gas pursuant to long-term, fixed fee or fee-based contracts. We intend to expand and diversify the scope of our energy distribution activities by adding new industrial plants, power plants, and municipal utilities as customers.

·         Minimizing commodity price exposure. Where possible, we intend to continue to pursue fixed fee, fee-based service agreements or back-to-back purchase and sale contracts, which allow us to minimize significant direct commodity price exposure.

·         Emphasizing long-term contracts. Where possible, we intend to continue to structure long-term contracts in order to increase our cash flow horizon.  Our current contracts related to our natural gas distribution and transmission activities are all renewed on an annual basis, a biennial basis, or on a long-term basis.  Our current contracts related to our natural gas gathering activities are all “life of lease”.  When evaluating acquisitions or the construction of new pipelines, we will consider the length of the prospective contract when determining whether or not to proceed. 

·         Pursuing strategic acquisitions. We intend to continue pursuing strategic acquisitions of midstream assets and companies that would diversify and extend our geographic, customer and business profile and provide visible organic growth opportunities for us.  Since October 2010, we have acquired six pipelines in three separate transactions.

·         Pursuing the construction of new pipelines.  We plan to evaluate the construction of new pipeline systems.  Many of the construction opportunities we seek will bypass existing pipelines owned by local distribution companies (“LDCs”) and provide direct service from large diameter pipelines to end users (“LDC bypasses”).  In particular, we seek to leverage a growing base of relationships with natural gas end users and marketers.

·         Reducing general and administrative expenses. Our goal is to become a low-cost provider of midstream energy services and to leverage our fixed costs.  We reduced general and administrative expenses from $1,583,226 incurred in the year ended December 31, 2010, to $1,364,046 incurred in the year ended December 31, 2011, a reduction of $219,180 or 14%.  The reduction in general and administrative expenses of $219,180 in 2011 compared to 2010 is in addition to the reduction of $749,944 we achieved in 2010 compared to 2009.  In the past year, we reduced investor relations costs, legal costs and salaries and benefits costs (by outsourcing operating and financial staff).  We will continue to review ways to reduce general and administrative expenses without sacrificing our ability to support and grow our operations.

·         Evaluation of sound financing alternatives. We plan to evaluate various financing alternatives to facilitate our growth, including corporate and project debt, equity and the creation of joint ventures and a master limited partnership.  We also intend to maintain financial flexibility by employing a prudent long-term capital structure.

·         Maintaining a financial alignment with shareholders: Our officers and board of directors collectively  own  5,949,331 shares of common stock (which includes shares of restricted common stock and common stock underlying stock options), representing approximately 24% of the total shares of common stock  outstanding (on a fully diluted basis) as of March 29, 2012.  Frederick M. Pevow, our President & CEO, owns 3,519,231 shares of common stock (which includes shares of restricted common stock and common stock underlying stock options) representing approximately 14% of the total shares of common stock outstanding (on a fully diluted basis) as of March 29, 2012.  We believe that significant insider ownership insures a vested interest by our management team and board of directors in our success.

Recent Developments

                The following is a brief list of significant developments since the appointment of a new management team and board of directors on June 3, 2010.

·         On February 29, 2012, we acquired a natural gas pipeline from Commerce Pipeline, L.P. (the "Commerce Pipeline") for $1,000,000 in cash.  The pipeline is located in Commerce, Texas and delivers natural gas into an aluminum smelting plant owned by Hydro Aluminum Metal Products North America pursuant to a long-term, fixed fee contract.  We financed the purchase price through a combination of cash on hand and the incurrence of additional indebtedness pursuant to an amendment to our loan agreement with Meridian Bank Texas N.A. (“Meridian Bank”).

·         On September 24, 2011, we 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 (the “Delmar Pipeline”).  In connection with the closing of the acquisition, we entered into a new long-term, fixed fee contract with Owens Corning to transport natural gas at a fixed monthly fee.

·         On November 23, 2010, we completed a private placement of 4,028,000 shares of common stock at a sale price of $0.25 per share for total gross proceeds of $1,007,000.  The Company used $1,000,000 of the proceeds to partially repay indebtedness then outstanding under the credit facility with Meridian Bank.  Our officers and directors purchased 728,000 shares of common stock in the private placement.

·         On October 18, 2010, we acquired four pipelines from Laser Pipeline Company, L.P. (“Laser”) for $1,100,000 in cash.  The four pipelines are located in Guadalupe and Shelby Counties, Texas, Miller County, Arkansas and Pettis County, Missouri (the “Tyson Pipeline Systems”).  The pipelines deliver natural gas on an exclusive basis to plants owned by Tyson Foods, Inc. (“Tyson”) pursuant to long-term, fee-based contracts with Tyson.  We financed the purchase price through a combination of cash on hand and bank debt. 

·         We reduced general and administrative expenses from $2,353,287 for the 2009 calendar year, the first full calendar year prior to the appointment of new management team and board of directors, to $1,364,046 for the 2011 calendar year, a savings of nearly $1.0 million per year.

Major Customers and Suppliers

During the year ended December 31, 2011, three companies, Cokinos Energy Corporation, ETC Marketing, Ltd., and Shell Energy North America supplied 35.3%, 32.4% and 32.3%, respectively, of our total natural gas purchases.  During the year ended December 31, 2010, Shell Energy North America supplied 100% of our total natural gas purchases.  Gross sales to customers representing 10% or more of total revenue for the years ended December 31, 2011 and 2010 were as follows:

The loss of our contract with Dart Container Corporation or either of our contracts with Owens Corning could have a material adverse effect on our business, results of operations and financial condition.

The natural gas industry is highly competitive.  We compete against other companies in the distribution, gathering, and transmission business for gas supplies and for customers.  Competition for gas markets and supplies is primarily based on the availability of upstream and downstream transportation facilities, the cost-effectiveness of downstream pipelines and processing facilities, service and satisfactory price.  In marketing, there are numerous competitors, including affiliates of intrastate and interstate pipelines, major producers, brokers and marketers.  Most of our competitors have capital resources greater than us and control greater supplies of gas.  Competition for marketing customers is primarily based on reliability and the price of delivered gas.

Regulations

Our intrastate natural gas pipeline transportation and sales activities are subject to various state laws and regulations, as well as orders of state regulatory bodies, including the Railroad Commission of Texas, the New York State Public Service Commission and the Arkansas Public Service Commission.  State regulatory bodies have the authority to regulate our transportation rates, though they generally have not investigated the rates or practices of our intrastate pipelines due to our participation in a competitive marketplace and the absence of complaints from our shippers.

Our pipelines are subject to numerous safety regulations with respect to their design, installation, testing, construction and operation.  Safety regulations for our intrastate pipelines are promulgated by state agencies generally in accordance with guidelines set forth by the United States Department of Transportation (“DOT”).

The Pipeline Safety Improvement Act of 2002 provides guidelines in the areas of testing, education, training and communication.  The Pipeline Safety Improvement Act requires pipeline companies to perform integrity tests on natural gas transmission pipelines that exist in high population density areas that are designated as “high consequence areas.”  Testing consists of hydrostatic testing, internal magnetic flux or ultrasonic testing, or direct assessment of the piping.  In addition to the pipeline integrity tests, pipeline companies must implement a qualification program to make certain that employees are properly trained.

On December 13, 2011, the United States Congress passed the “Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011” (the “Act”).  The President signed the Act into law on January 3, 2012.  Under the Act, maximum civil penalties for certain violations have been increased from $100,000 to $200,000 per violation per day, and from a total cap of $1.0 million to $2.0 million.  In addition, the Act reauthorizes existing pipeline safety programs through September 30, 2015, and directs the Secretary of Transportation to undertake a number of reviews, studies and reports, some of which may result in additional natural gas pipeline safety rulemaking.  Some of these directives include:

·         The Secretary of Transportation must revise regulations establishing time limits for notification of pipeline facility accidents and incidents to a minimum of not more than one hour after discovery of an accident or incident;

·         The Secretary of Transportation must submit a report to Congress on leak detection systems utilized by operators and promulgate, where technically, operationally and economically feasible, regulations requiring leak detection systems where practicable;

·         Within 18 months, the Secretary of Transportation must conduct an evaluation to determine whether integrity management system requirements already in place for pipelines in High Consequence Areas (“HCAs”) should be expanded to pipelines beyond HCAs;

·         Within two years, the Secretary of Transportation must submit to Congress a report on the results of a review of existing federal and state regulations for gas and hazardous liquid gathering lines located offshore, including within inlets of the Gulf of Mexico, for the purpose of determining whether the Secretary of Transportation should issue regulations subjecting offshore gathering lines to the same standards and regulations as other hazardous liquid gathering lines; and

·         Within two years, the Secretary of Transportation must determine whether to require the use of automatic or remote-controlled shut-off valves on new and entirely replaced transmission pipeline facilities.

A number of the provisions of the Act have the potential to cause owners and operators of pipeline facilities to incur significant capital expenditures and/or operating costs.  Any additional requirements resulting from these directives are not expected to impact us differently than our competitors.  We will continue to monitor the DOT’s efforts to remain abreast of their potential impact to us.

Environmental and Safety Concerns

Our business operations are subject to federal, state and local laws and regulations relating to environmental protection, pollution and human health and safety.  For example, if an accidental leak, release or spill of liquid petroleum products, chemicals or other hazardous substances occurs at or from our pipelines we may experience significant operational

disruptions, and we may have to pay a significant amount to clean up the leak, release or spill, pay for government penalties, address natural resource damages, compensate for human exposure or property damage or a combination of these and other measures.  Furthermore, new projects may require approvals and environmental analysis under federal and state laws, including the National Environmental Policy Act and the Endangered Species Act.  The resulting costs and liabilities could materially and negatively affect our business, financial condition, results of operations and cash flows.

Environmental and human health and safety laws and regulations are subject to change.  The clear trend in environmental regulation is to place more restrictions and limitations on activities that may be perceived to affect the environment, wildlife, natural resources and human health and safety.  There can be no assurance as to the amount or timing of future expenditures for environmental, health and safety regulation compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate.  Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and cash flows.

 We believe we have obtained, and are in current compliance with all necessary and material permits, and that our operations are in substantial compliance with applicable material governmental regulations. The cost of complying with these regulations has not historically been material.

 Hazardous Substances

The Comprehensive Environmental Response, Compensation and Liability Act, also known as CERCLA or the Superfund law, and analogous state laws, impose joint and several liability without regard to fault or the legality of the original conduct, on certain classes of potentially responsible persons for releases of hazardous substances into the environment.  These persons include the owner or operator of a site and companies that disposed or arranged for the disposal of the hazardous substances found at the site.  CERCLA authorizes the U.S. EPA and, in some cases, other lead agencies or third parties to take actions in response to threats to public health or the environment and to seek to recover from the responsible classes of persons the costs they incur, in addition to compensation for natural resource damages, if any.  Although petroleum is excluded from CERCLA’s definition of a hazardous substance, in the course of our ordinary operations we have and will generate materials that may fall within the broad CERCLA definition of hazardous substance.  By operation of law, if we are determined to be a potentially responsible person, we may be responsible under CERCLA for all or part of the costs required to clean up sites at which such materials are present, in addition to compensation for natural resource damages, if any.

Our operations are subject to the federal Clean Air Act (“Clean Air Act’), its implementing regulations, and analogous state regulations.  We believe that the operations of our pipelines are in substantial compliance with such statutes and regulations.

On December 15, 2009, the EPA published its final findings that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes.  These findings allow the EPA to adopt and implement regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act.  Accordingly, the EPA has adopted regulations that would require a reduction in emissions of greenhouse gases from motor vehicles and could trigger permit review for greenhouse gas emissions from certain stationary sources.  In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2011 for emissions occurring in 2010.  On November 8, 2010, the EPA finalized regulations to expand the existing greenhouse gas monitoring and reporting rule to include onshore and offshore oil and natural gas production facilities and onshore oil and gas processing, transmission, storage, and distribution facilities.  Reporting of greenhouse gas emissions from such facilities is required on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011.  The EPA’s rules relating to emissions of greenhouse gases from large stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent EPA or state environmental agencies from implementing the rules.  Further, Congress has considered, and almost one-half of the states have adopted, legislation that seeks to control or reduce emissions of greenhouse gases from a wide range of sources.

The EPA’s new regulations for the monitoring, reporting, record keeping and permitting of greenhouse gas emissions from stationary sources contain lengthy, complex provisions that may result in the imposition over the next several years of certain pollution control requirements with respect to air emissions from the operations of our pipelines.   Depending on the nature of those requirements and any additional requirements that may be imposed by state and local regulatory authorities, we may be required to incur capital and operating expenditures over the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals and addressing other air emission−related issues.   At this time, we do not operate compressor stations which are regulated under the Clean Air Act, although we may in the future.  We are unable to fully estimate the effect on earnings or operations or the amount and timing of such required capital expenditures; however, we do not believe that we will be materially adversely affected by any such requirements.

Water

      During 2010, the U.S. federal government established the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) to replace the U.S. Minerals Management Service (MMS), largely in response to the April 2010 blowout of the Macondo well and resulting oil spill in the Gulf of Mexico.  The U.S. federal government imposed a drilling moratorium in the deepwater Gulf of Mexico that extended until October 2010.  BOEMRE issued several Notices to Lessees (NTLs) and other safety regulations implementing additional safety and certification requirements applicable to drilling activities in the Gulf of Mexico that have resulted in operations and projects being delayed or suspended.  These NTLs and regulations include requirements by operators to (1) submit well blowout prevention measures and contingency plans, including demonstrating access to subsea blowout containment resources; (2) abide by new permitting standards requiring detailed, independently certified descriptions of well design, casing, and cementing; (3) follow new performance-based standards for offshore drilling and production operations; and (4) certify that the operator has complied with all regulations.  These regulations issued by the BOEMRE include NTL 2010-G05, the “Idle Iron Guidance.”

In the U.S. Gulf of Mexico, regulations generally require wells to be plugged, offshore platforms decommissioned, pipelines abandoned, and the well site cleared within twelve months of the expiration of an oil or gas lease.  However, NTL 2010-G05 establishes well abandonment and decommissioning requirements that are no longer tied to lease expiration.  The maturity and production decline of Gulf of Mexico oil and gas fields continues to cause an increase in the number of wells to be plugged and abandoned and platforms and pipelines to be decommissioned.  In October 2011, the BOEMRE’s responsibilities were divided between the newly created Bureau of Ocean Energy Management (BOEM) and the Bureau of Safety and Environmental Enforcement (BSEE), the latter of which will oversee the provisions of the “Idle Iron Guidance”.

Since the April 20, 2010, blowout on the Macondo well, operations in the U.S. Gulf of Mexico have been affected by an increased regulatory environment.  The resulting federal regulatory requirements have significantly reduced the U.S. Gulf of Mexico drilling activity.  Although permitting levels increased somewhat during 2011, the pace of approvals for new drilling activity in the Gulf of Mexico lags pre-Macondo levels.  BOEMRE regulations, including notices to U.S. Gulf of Mexico operators, have resulted in some operations and projects being curtailed or suspended.  Although a drilling moratorium that was issued immediately following the Macondo blowout was lifted in October 2010, the backlog of permits waiting to be issued for operations in the shallow water, and regulatory uncertainties regarding the deepwater activities, are expected to continue to negatively affect our prospects for increased offshore gas production.  Although we are unable to predict the full continuing impact of these factors on future operating results going forward, we expect our customers’ offshore activity levels to continue to be less than they were prior to April 2010.  Future regulatory requirements could further delay our customers’ offshore production activities, reduce our revenues, and increase our operating costs, resulting in reduced cash flows and profitability.

Climate Change

                Studies have suggested that emissions of certain gases, commonly referred to as greenhouse gases (“GHG”), may be contributing to warming of the Earth’s atmosphere. Methane, a primary component of natural gas, and carbon dioxide, which is naturally occurring and also a byproduct of the burning of natural gas, are examples of greenhouse gases.  It is not possible at this time to predict what action, if any, the U.S. Congress may take in regard to greenhouse gas legislation.

            As discussed above under “—Air Emissions,” the U.S. EPA adopted new regulations under the Clean Air Act that took effect in early 2011 and that establish requirements for the monitoring, reporting, record keeping and permitting of greenhouse gas emissions from stationary sources. These regulations include the reporting of greenhouse gas emissions in the United States from specified large greenhouse gas emission sources.  Our operations at this time do not include compressor stations and gas processing plants, which emit various types of greenhouse gases, primarily methane and carbon dioxide, although if we do operate such stations or plants in the future, such legislation or regulation would increase our costs related to operating and maintaining our facilities, may require us to install new emission controls on our facilities, and likely would require us to obtain allowances for our greenhouse gas emissions, pay taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program.

                The operations of our customers could also be negatively impacted by more recently proposed GHG legislation or new regulations resulting in increased operating or compliance costs.  Some of the proposed federal and state “cap and trade” legislation would require businesses that emit GHG’s to buy emission credits from government, other businesses, or through an auction process.  In addition, our customers could be required to purchase emission credits for GHG emissions.  While it is not possible at this time to predict the final form of “cap and trade” legislation, any new federal or state restrictions on GHG emissions could result in material increased compliance costs, additional operating restrictions and an increase in the cost of raw materials and products produced by our customers.

Operational Hazards and Insurance

Pipelines and equipment may experience damage as a result of an accident or natural disaster.  These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations.  We maintain insurance of various types and varying levels of coverage that we consider adequate under the circumstances to cover our operations and properties.  The insurance policies are subject to deductibles and retention levels that we consider reasonable and not excessive.  Consistent with insurance coverage generally available to the industry, our insurance policies provide limited coverage for accidental property and casualty occurrences.  However, such insurance does not cover every potential risk associated with operating pipelines, including the potential loss of significant revenues.

Title to Properties and Rights-of-Way

We believe that we have generally satisfactory title to the properties we own and use in our businesses, subject to liens for current taxes, liens incident to minor encumbrances, and easements and restrictions, which do not materially detract from the value of such property, the interests in those properties or the use of such properties in our businesses.  Our pipelines and related facilities are located on real property owned or leased by us. In some cases, the real property we lease is on federal, state or local government land.

We generally do not own the land on which our pipelines are constructed.  Instead, we obtain the right to construct and operate the pipelines on other people’s land for a period of time.  Substantially all of our pipelines are constructed on rights−of−way granted by the apparent record owners of such property.  In many instances, lands over which rights−of−way have been obtained are subject to prior liens that have not been subordinated to the right−of−way grants.  We have no knowledge of any challenge to the underlying fee title of any material fee, lease, easement, right-of-way, permit or license held by us or to our rights pursuant to any material deed, lease, easement, right-of-way, permit or license, and we believe that we have satisfactory rights pursuant to all of our material leases, easements, rights-of-way, permits and licenses.  Permits have been obtained from public authorities to cross over or under, or to lay facilities in or along, water courses, county roads, municipal streets and state highways, and in some instances, such permits are revocable at the election of the grantor, or, the pipeline may be required to move its facilities at its own expense.  Permits also have been obtained from railroad companies to run along or cross over or under lands or rights−of−way, many of which are also revocable at the grantor’s election.  Some such permits require annual or other periodic payments. In a few minor cases, property for pipeline purposes was purchased in fee.

Employees

As of December 31, 2011, we had three employees, all of which are full time employees.

ITEM 1A.  RISK FACTORS.

This item is not applicable for smaller reporting companies such as Gateway.  However, see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Future Results or the Value of Our Common Stock.

ITEM 1B.  UNRESOLVED STAFF COMMENTS.

We do not have any unresolved staff comments to disclose under this Item.

ITEM 2.  PROPERTIES.

Onshore Pipeline Systems

We own the following nine active onshore pipeline systems in the continental United States:

·         Waxahachie Pipeline System: a 2 to 8-inch diameter, fourteen-mile delivery system that transports natural gas for sale to industrial users in Waxahachie, Ellis County, Texas.  

·         Tyson Pipeline Systems: four 4-inch diameter pipelines between one and five miles in length that deliver natural gas into poultry processing and rendering plants owned by Tyson Foods, Inc. The pipelines are located in Center, Texas; Seguin, Texas; Texarkana, Arkansas; and Sedalia, Missouri.

·         Delmar Pipeline: a 3-inch diameter, 3,000 feet pipeline that transports natural gas to an Owens Corning plant in Delmar, Albany County, New York.

·         Madisonville Pipeline: a 10-inch diameter, ten mile pipeline located near Madisonville, Madison County, Texas which transports natural gas from the Madisonville treating facility to two major pipelines.

·         Hickory Creek Pipeline System: a gathering system located in Denton County, Texas in the core area of the Barnett Shale and currently servicing two significant producers.  There are currently fifteen producing wells connected to this system.

·         Commerce Pipeline: a 4-inch diameter, three mile pipeline that transports natural gas to a Hydro Aluminum plant in Commerce, Hunt County, Texas.

Offshore Pipeline Systems

Gateway Offshore Pipeline Company owns eight pipelines that service producers in federal waters of the Gulf of Mexico and Galveston Bay.  These systems and related facilities are in waters up to 650 feet in depth and provide us the capability to gather and transport gas and liquid hydrocarbons to various markets.  Our offshore systems consist of approximately 108 miles of three-inch to 16-inch diameter pipelines and related equipment which transport the natural gas and liquid hydrocarbons primarily under fee-based contracts.

System Capacity

The capacity of a pipeline is primarily a function of its diameter and length and its inlet and outlet pressures.  Based upon normal operating pressures, our systems have a daily throughput capacity of over 807,000 MMBtu per day, which significantly exceeds the average daily throughput in December 2011 of approximately 33,700 MMBtu per day.

Corporate Property

In addition to the operating properties described above, we lease office space and own certain office equipment in our corporate office located at 1415 Louisiana Street, Suite 4100, Houston, Texas 77002.

ITEM    3.  LEGAL PROCEEDINGS.

We are involved in ordinary, routine litigation from time to time incidental to our business.  We are not presently a party to any other legal proceeding, the adverse determination of which, either individually or in the aggregate, would be expected to have a material adverse effect on our business or financial condition.

ITEM    4.  MINE SAFETY DISCLOSURES.

This item is not applicable for Gateway.

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

Market Information

Our common stock is traded on the Over-The-Counter (“OTC”) Bulletin Board under the symbol “GNRG”.  The following table sets forth the quarterly high and low bid prices for the common stock as reported on the OTC Bulletin Board for the periods indicated. These prices are based on quotations between dealers, and do not reflect retail mark-up, mark-down or commissions, and may not necessarily represent actual transactions.

Holders

As of March 29, 2012, there were approximately 659 holders of record of our common stock.

Dividends

To date, we have not declared or paid any dividends on common stock.  Our payment of dividends, if any, is within the discretion of our board of directors and will depend on our earnings, if any, capital requirements and financial condition, as well as other relevant factors. On December 7, 2009, we entered into a Credit Agreement with Meridian Bank, which has since been amended many times.  This agreement restricts our ability to pay dividends.

Securities Authorized for Issuance Under Equity Compensation Plans

                This information can be found under the heading ITEM 12.   SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.

ITEM 6.  SELECTED FINANCIAL DATA.

This item is not applicable for smaller reporting companies such as Gateway.

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

            The following management's discussion and analysis should be read in conjunction with our consolidated financial statements and the notes thereto included elsewhere in this Annual Report on Form 10-K.  This discussion and the discussion of Gateway’s business beginning in Item 1 of this Annual Report, also contains trend analysis and other forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended.  These forward−looking statements reflect the expectations, beliefs, plans and objectives of management about future financial performance and assumptions underlying management's judgment concerning the matters discussed, and accordingly, involve estimates, assumptions, judgments and uncertainties.  Actual results could differ materially from those projected in the forward-looking statements throughout this document as a result of the risk factors set forth below in the section entitled “Factors Affecting Future Results” and elsewhere in this document.

Critical Accounting Policies

The following accounting policies are considered by management to be the most critical to the fair presentation of our financial condition, results of operations and cash flows.  The policies are consistently applied in the preparation of the accompanying consolidated financial statements.    

Use of Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles (“GAAP”) requires us 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.  Our 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.  Onshore transportation revenues are recognized at the redelivery point, which is the point at which another party takes physical custody of the natural gas or liquid hydrocarbons.  Offshore transportation revenues are recognized at our receipt point.

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 35 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 Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 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 reassess the obligation to determine whether a change in the estimated obligation is necessary.  We also evaluate 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), we will accordingly update our assessment.

Accounting Standards Updates

None of the Accounting Standards Updates (ASU) that we adopted and that became effective January 1, 2011, had a material impact on our consolidated financial statements.

ASU No. 2011-04

On May 12, 2011, the FASB issued ASU No. 2011-04, “Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs.”  This ASU amends U.S. generally accepted accounting principles (U.S. GAAP) and results in a consistent definition of fair value and common requirements for measurement of and disclosure about fair value between U.S. GAAP and international financial reporting standards (IFRS).  The amendments in this ASU change the wording used to describe many of the requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements; however, the amendment’s requirements do not extend the use of fair value accounting, and for many of the requirements, the FASB did not intend for the amendments to result in a change in the application of the requirements in the “Fair Value Measurement” Topic of the Codification.  Additionally, ASU No. 2011-04 includes some enhanced disclosure requirements, including an expansion of the information required for Level 3 fair value measurements.  For us, ASU No. 2011-04 was effective January 1, 2012, and the adoption of this ASU is not expected to have a material impact on our consolidated financial statements.

ASU Nos. 2011-05 and 2011-12

On June 16, 2011, the FASB issued ASU No. 2011-05, “Comprehensive Income (Topic 220): Presentation of Comprehensive Income.”  This ASU eliminates the current option to report other comprehensive income and its components in the statement of changes in equity.  An entity can elect to present items of net income and other comprehensive income in one continuous statement or in two separate, but consecutive, statements.

ASU No. 2011-05 also requires reclassifications of items out of accumulated other comprehensive income to net income to be measured and presented by income statement line item in both the statement where net income is presented and the statement where other comprehensive income is presented.  However, on December 23, 2011, the FASB issued ASU No. 2011-12, “Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05” to defer this new requirement.  For us, both ASU No. 2011-05 and ASU No. 2011-12 were effective January 1, 2012.  Since these ASUs pertain to presentation and disclosure requirements only, the adoption of these ASUs is not expected to have a material impact on our consolidated financial statements.

ASU No. 2011-08

On September 15, 2011, the FASB issued ASU No. 2011-8, “Intangibles—Goodwill and Other (Topic 350): Testing Goodwill for Impairment.”  This ASU allows an entity to first assess qualitative factors to determine whether it is necessary to perform the two-step quantitative goodwill impairment test prescribed by current accounting principles.  However, the quantitative impairment test is required if an entity believes, as a result of its qualitative assessment, that it is more-likely-than-not that the fair value of a reporting unit is less than its carrying amount.  An entity can choose to perform the qualitative assessment on none, some or all of its reporting units.  Moreover, an entity can bypass the qualitative assessment for any reporting unit in any period and proceed directly to the quantitative goodwill impairment test, and then resume performing the qualitative assessment in any subsequent period.  For us, ASU No. 2011-8 was effective January 1, 2012, and the adoption of this ASU is not expected to have a material impact on our consolidated financial statements.  

ASU No. 2011-11

On December 16, 2011, the FASB issued ASU No. 2011-11, “Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities.”  This ASU requires disclosures to provide information to help reconcile differences in the offsetting requirements under U.S. GAAP and IFRS.  The disclosure requirements of this ASU mandate that entities disclose both gross and net information about financial instruments and transactions eligible for offset in the statement of financial position as well as instruments and transactions subject to an enforceable master netting arrangement or similar agreement.  ASU No. 2011-11 also requires disclosure of collateral received and posted in connection with master netting arrangements or similar arrangements.  The scope of this ASU includes derivative contracts, repurchase agreements, and securities borrowing and lending arrangements.  Entities are required to apply the amendments of ASU No. 2011-11 for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods.  All disclosures provided by those amendments are required to be provided retrospectively for all comparative periods presented. We are currently reviewing the effect of ASU No. 2011-11.

Results of Operations

General

                All of our operations are onshore in the continental United States and offshore in federal and state waters of the Gulf of Mexico.  We separately review and evaluate the operations of each of our gas distribution, transmission and gathering systems individually; however these operations are aggregated into one reportable segment due to the fact that all of our 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.

Our pipeline systems include distribution systems, which transport natural gas from large diameter, long distance pipelines (trunklines) to end users, and gathering systems, which transport natural gas and liquids from oil and gas wells to trunklines.  Our distribution systems consist of the Waxahachie Pipeline System, the Tyson Pipeline Systems, the Delmar Pipeline and the Commerce Pipeline.  Our gathering systems consist of the Hickory Creek Pipeline System, the Madisonville Pipeline and miscellaneous pipeline systems located in federal and state waters of the Gulf of Mexico.

Our distribution activities do not require additional capital expenditures to connect new wells nor do they require additional drilling by our customer in order to replace revenues; nonetheless they do require plant operations by our customers in order to generate revenues.  All of our pipeline systems generate revenues pursuant to fee-based service agreements, with the exception of our Waxahachie Pipeline System, which generates revenues pursuant to back-to-back purchase and sale agreements.

We evaluate our results based on operating margin, which is defined as revenues less cost of purchased gas and operating and maintenance expenses.  Such amounts are before 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 is presented below under the heading Non-GAAP Financial Measure.

The Henry Hub closing monthly index price for natural gas during the year ended December 31, 2011, averaged $4.04 per MMBtu, compared to $4.39 for the same period of the prior year.  In the accompanying financial statements, our revenues from sales of natural gas, along with the cost of natural gas purchased, decreased proportionately from prior year levels.  Because we buy and sell gas under back-to-back contracts that are priced at the beginning of the month, based upon established gas indices to minimize commodity price risk, our net operating margin is relatively insensitive to fluctuations in the market price of gas.  

Results of Operations for the Years Ended December 31, 2011 and 2010

Revenues

Our total revenues were $7,073,987 for the year ended December 31, 2011, which represented a slight decrease of $201,910 from the $7,275,897 of total revenues we recognized during the year ended December 31, 2010. 

Revenues from sales of gas on our Waxahachie distribution system decreased $51,695 for the year ended December 31, 2011 as compared to 2010.  An approximate 5.1% increase in sales volumes, to 2,936 MMBtu/d, at Waxahachie accounted for an increase of $255,073 in revenues but was offset by a decline in the gas sales price, which accounted for a decrease of $306,768 in revenues.  The decrease in revenues due to lower gas prices from our Waxahachie system, however, was largely offset by reductions in the cost of purchased gas, as volumes are bought and sold pursuant to “back-to-back” contracts based on monthly price indices. 

Our transportation revenues decreased by approximately $122,538 for the year ended December 31, 2011, as compared to 2010.  Transportation revenues increased by $228,835 primarily due to owning our operations which deliver natural gas to plants owned by Tyson Foods (the “Tyson Pipeline Systems”) for a full year in 2011, versus only approximately three months during 2010.  Transportation revenues also increased by $49,000 due to the acquisition, on September 24, 2011, of our pipeline which delivers natural gas to a plant owned by Owens Corning in Delmar, New York (the “Delmar Pipeline”).  The combined increase in transportation revenues of $277,835 from the two aforementioned distribution systems was offset by net decreases of $400,373 in transportation revenues attributable to production declines on natural gas wells connected to our gathering systems. 

Revenues from reimbursable costs and other revenue decreased by $27,677 during the year ended December 31, 2011, as compared to 2010.  This decrease was primarily attributable to decreased operating fees from the operator of High Island Offshore Pipeline, which are reimbursed by our customers on our High Island A-332 Pipeline.

We believe that transportation revenues from our gathering systems will continue to decrease for at least the first three quarters of 2012 but may stabilize or even increase in late 2012 and 2013 due to drilling and workover activities planned by our customers, in particular those connected to our East Cameron Block 338 and Hickory Creek pipeline systems.  There are no assurances that such planned drilling and workover activities will ever contribute to revenues, as they are dependent on oil and gas prices, drilling rig availability and dry hole risk, among other factors.

Operating Margin

We define operating margin 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.  Operating margin was $1,961,383 for the year ended December 31, 2011, which was relatively unchanged from the $1,968,705 we recognized during 2010. 

Operating margin contribution from our distribution systems was $894,907 during 2011, a $291,817 increase compared to the $603,090 contribution in 2010.  Our Tyson pipeline systems contributed $228,717 to operating margin during 2011, an increase of $179,542 from 2010, primarily as a result of our ownership of these assets acquired from Laser for the entire year.  In addition, our Delmar pipeline contributed $27,558 of operating margin during 2011 beginning from the date of its acquisition from American Midstream on September 24, 2011.  Finally, our Waxahachie distribution system contributed $638,632 to operating margin during 2011, an increase of $84,717 compared to 2010, as a result of increased volumes and lower natural gas purchase costs relative to index prices.  We expect operating margin from our total distribution systems to increase in 2012 compared to 2011, as a result of our ownership of the Delmar pipeline for the entire year and the ownership of our newly acquired Commerce pipeline for the period beginning March 1, 2012.

Operating margin contribution from our gathering systems was $1,065,656 during 2011, a $273,991, or 20%, decrease compared to the $1,339,647 contribution in 2010.  This decrease was primarily attributable to production declines from existing oil and gas wells connected to these systems. We expect further decreases in operating margin from our gathering systems for the full year 2012 compared to 2011, also primarily attributable to production declines from existing oil and gas wells connected to these systems.  Operating margin from our gathering systems might stabilize, or even increase, by late 2012 if customers on some of our gathering systems are successful and remain on schedule with announced plans to drill new wells.

                General and Administrative Costs

General and administrative expenses were $1,364,046 for the year ended December 31, 2011, which represented a decrease of $219,180 from the $1,583,226 in such expenses we recognized for the year ended December 31, 2010.  Across the board decreases were partially offset by a $67,157 increase in stock compensation due to current year grant activity and as a result of a $49,676 reversal of prior expenses during 2010 due to the forfeiture of unvested options by prior management.   During 2011, there was only $3,197 for such prior expense reversals due to forfeitures.  We expect general and administrative expenses during 2012 to be comparable to those realized in 2011, as we continue to manage our overall level of fixed costs.

                Acquisition Costs

We incurred acquisition related costs of $84,323 during the year ended December 31, 2011, primarily related to the acquisition of our Delmar Pipeline from American Midstream completed on September 24, 2011, and the acquisition of our Commerce pipeline completed on February 29, 2012.

We incurred acquisition related costs of $109,950 during the year ended December 31, 2010, which were related to our Hickory Creek and Laser asset acquisitions.  

Consent Solicitation and Severance Costs

Consent solicitation and severance costs of $1,544,884 for the year ended December 31, 2010, 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.

                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 certain 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 limited 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 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, we 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 our property and equipment and $129,012 to the carrying value of our intangible assets.

Asset Retirement Obligation Accretion

During 2011, we established an estimated asset retirement obligation of $1,013,279, due to the change in estimate brought about by the aforementioned change in our estimated abandonment dates, ongoing discussions with our customers and updating the costs to retire these assets.  This liability will be accreted to our total undiscounted estimated liability over future periods until the date of such abandonment.  During 2011, we recognized $24,436 of such accretion expense.

Depreciation, Depletion and Amortization

During 2011, our depreciation, depletion and amortization expense decreased $111,659, to $623,062, as compared to $734,721 for 2010, primarily as a result of a lower depreciable balance attributable to the asset impairments recorded in 2011 and 2010.

Other Income (Expense)

Our interest expense, net fluctuates directly with the amount of outstanding insurance notes payable and the amount of long term debt we have outstanding, and remained relatively constant between the years ended December 31, 2011 and 2010.

Discontinued Operations

In June 2009, we sold our Shipwreck gathering system consisting of an offshore platform and related pipelines, as well as a related onshore facility known as the Crystal Beach terminal (the “Shipwreck/Crystal Beach Assets”).  In a separate transaction, we also sold our Pirates’ Beach gathering system (the “Pirates’ Beach Assets”).

The Shipwreck/Crystal Beach Assets were sold to Impact Exploration & Production, LLC for consideration consisting of $200,000, payable in four quarterly installments, and the assumption of liabilities, including abandonment and retirement obligations, with an effective date of June 30, 2009.  We received the first installment on the note as of December 31, 2009, but were uncertain as to the timing of the collection of the remaining three installments.  As such, we calculated the gain on sale of assets according to ASC Topic 605 “Revenue Recognition” using the cost recovery method.  As a result of the sale, we recognized a pre-tax gain of $213,780 and a pre-tax deferred gain of $150,000, which was deferred and recognized as the remaining installments were received.  In November 2010, we received payment of $127,500 to retire the note and recognized a pre-tax gain of $127,500 ($83,073 after tax) during 2010. 

Liquidity and Capital Resources

We had available cash of $554,054 at December 31, 2011.

Net cash provided by continuing operating activities totaled $897,117 for the year ended December 31, 2011, compared to net cash used in continuing operating activities of $1,307,368 during 2010.  The significant $2,204,485 increase in cash flow from operating activities is primarily due to:

·         consent solicitation and severance costs of $1,544,884 for the year ended December 31, 2010, incurred for legal and proxy preparation costs 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;

·         the receipt of a cash deposit of $250,000 returned in 2011 by our former gas supplier when we contracted with a new gas supplier; and

·         a decrease in general and administrative expenses, net of non-cash, stock based compensation expenses, of $322,874 for the year ended December 31, 2011 as compared to 2010.

 We used $129,304 of cash in investing activities during the year ended December 31, 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 had an additional $79,304 in capital expenditures, the largest of which involved the installation of a cathodic protection system at our Waxahachie system, which will lengthen the expected life of the system.  During 2010, we used $4,845,234 of cash in investing activities, primarily for the purchase of our Hickory Creek Gathering System and Laser assets.

For the year ended December 31, 2012, we have budgeted approximately $1.0 million for the acquisition of the Commerce pipeline asset, $331,000 in asset retirement costs and $25,000 in capital expenditures to maintain our onshore pipelines and related equipment.  In addition, we expect to incur another $450,000 in asset retirement costs in 2013.  We believe a combination of our net cash provided by operating activities, cash position and asset sales will be sufficient to fund our debt service, asset retirement obligations and maintenance capital expenditures for the foreseeable future; however, our liquidity will be dependent to some extent on future drilling and workover activities by our customers on wells connected to our gas gathering systems as well as our ability to successfully consummate asset sales.

Our business growth strategy includes the acquisition and construction of new pipeline systems.  We are actively exploring the possibility of seeking additional outside capital to allow us to implement our growth strategy, and such new capital may take several forms.  We believe we cannot finance the acquisition and construction of new pipeline systems without a significant infusion of new capital.  There is no guarantee that we will be able to raise outside capital or be able to sell assets on favorable terms or at all.  

During 2010, we executed premium finance agreements for our 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.  During 2011, we executed premium finance agreements with respect to the renewal of some of these policies totaling $27,194.  As of December 31, 2011, we had a balance due of $33,915 on these notes.

On December 7, 2009, we entered into a Credit Agreement (the “Loan Agreement”) with Meridian Bank (“Meridian”) regarding a revolving credit facility provided by Meridian.  The original borrowing base under the Loan Agreement had been established at $3.0 million, which originally could be increased at the discretion of Meridian to an amount not to exceed $6.0 million.  The Loan Agreement is secured by all of our assets and had an original term of 39 months maturing on April 30, 2012.  In 2011, the First and Second Amendments to the Loan Agreement shortened the maturity date to November 30, 2011, in consideration of Meridian refraining to institute a minimum commitment reduction.  On December 9, 2011, we further amended the Loan Agreement to extend the maturity date to April 30, 2012, setting the loan amount at $2,300,000, and interest on outstanding balances accruing at The Wall Street Journal prime rate, plus one and a half percent, with a minimum rate of 6.0% per annum, payable monthly.  Unused borrowing base fees are 0.50% per year and the Loan Agreement contains financial covenants defining various financial measures and levels of these measures.  We were in compliance with all covenants at December 31, 2011.   As of December 31, 2011, there was a $2,275,000 balance on the facility. 

On February 29, 2012, in connection with our acquisition of the Commerce pipeline asset, we entered into a

Fourth Amendment to the Loan Agreement, pursuant to which:

·         Our borrowings under the Loan Agreement were limited solely to a term loan of $2,995,000 (the “Term Note”), all of which was advanced on or before February 29, 2012 (in addition to an outstanding letter of credit obligation of $137,500);

·         Commencing in each calendar quarter ending June 30, 2012, we are required to make a payment to Meridian to reduce the outstanding principal balance owing under the Term Note equal to seventy five percent (75%) of our net cash provided by operating activities, less cash used in investing activities (excluding acquisitions and growth projects), less required monthly payments of principal and interest payments on the Term Note;

·         The pipeline acquired from Commerce Pipeline and certain other collateral was pledged as security for the Term Note;

·         We are required to maintain a debt to tangible net worth ratio of 1.90 to 1.00; a current ratio of 1.25 to 1.00 and a debt service coverage ratio of 1.50 to 1.00;

·         We are required to pay a principal and interest payment of $58,000 per month under the Term Note; and

·         The Term Note has a maturity date of June 30, 2013.

In accordance with FASB Topic 470, “Debt”, since we entered into the Fourth Amendment to the Loan Agreement prior to the issuance of our December 31, 2011 consolidated financial statements, we reclassified that portion of the Term Note not requiring repayment during the next twelve months, as of December 31, 2011, to non-current liabilities.

On November 23, 2010, we completed a private placement of 4,028,000 shares of common stock at a price of $0.25 per share for total gross proceeds of $1,007,000.  We used $1,000,000 of the proceeds from the sale of the common stock to partially repay the outstanding indebtedness under the credit facility with Meridian Bank Texas, N.A.  The common stock was offered and sold on a private placement basis to selected accredited investors (as defined in Rule 501(a) of Regulation D of the Securities Act of 1933, as amended (the “Securities Act”)), in reliance on the exemption from registration contained in Rule 506 of Regulation D of the Securities Act. 

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements at December 31, 2011; however, see Note 9 to the consolidated financial statements regarding Commitments and Contingencies.

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:

Factors Affecting Future Results or the Value of Our Common Stock

Our principal objective is to enhance stockholder value through the execution of certain strategies.  These strategies include, among other things: (i) focusing on gathering, transporting, and distributing natural gas; (ii) expanding the Company’s asset base in the existing core geographic areas; and (iii) acquiring or constructing properties in one or more new core areas.

We have substantial debt which could adversely affect our financial health and make us more vulnerable to adverse economic conditions. 

As of March 29, 2012, we had approximately $2,995,000 of indebtedness outstanding under our term loan (in addition to an outstanding letter of credit obligation of $137,500) with Meridian.  This level of debt could have important consequences, such as (i) limiting our ability to obtain additional financing to fund our working capital, capital expenditures, debt service requirements or potential growth or for other purposes; (ii) limiting our ability to use operating cash flow in other areas of our business or to pay distributions because we must dedicate a substantial portion of these funds to make payments on our debt; (iii) placing us at a competitive disadvantage compared to competitors with less debt; and (iv) increasing our vulnerability to adverse economic and industry conditions.

Commencing on March 31, 2012, we are required to pay a mandatory principal and interest payment of $58,000 per month under the term loan.  In addition to the mandatory principal and interest payments, commencing in each calendar quarter ending June 30, 2012, we are required to make a quarterly payment to Meridian to reduce the outstanding principal balance owing under the Term Note equal to seventy five percent (75%) of our net cash provided by operating activities, less cash used in investing activities (excluding acquisitions and growth projects), less mandatory monthly payments of principal and interest on the Term Note.  

On or prior to the maturity date of June 30, 2013, we will be required to refinance this indebtedness.  As a result, we are and expect to be subject to the risks normally associated with debt financing including: that interest rates may rise; that our cash flow will be insufficient to make required payments of principal and interest; that we will be unable to refinance some or all of our debt; that any refinancing will not be on terms as favorable as those of the existing debt; that debt service obligations will reduce funds available to grow our business; that any default on our debt, due to noncompliance with financial covenants or otherwise, could result in acceleration of those obligations; and that we may be unable to refinance or repay the debt as it becomes due.  An increase in interest rates would reduce our net income and funds from operations.  We may not be able to refinance or repay debt as it becomes due which may force us to refinance or to incur additional indebtedness at higher rates and additional cost or, in the extreme case, to sell assets or seek protection from our creditors under applicable law.

We have a history of operating losses.

We have incurred significant losses.  Our net losses were $2,448,159 and $2,593,564 for the years ended December 31, 2011 and 2010, respectively.  In addition, we expect another decrease in operating margin from our gathering systems for the full year 2012, as compared to 2011, and a net loss for 2012.   There are many factors influencing our operations that are beyond our control that may cause future losses, including declining production rates from existing oil and gas wells connected to our systems, decreased producer investment near our existing pipeline systems and natural gas purchase costs relative to index prices.  There can be no assurance that we will achieve or sustain profitability in the future.  Future losses could have a material adverse affect on our ability to fund future operations, as well as our results of operations and financial conditions.  

Our acquisition strategy and construction projects require access to new capital.  Tightened capital markets or more expensive capital would impair our ability to grow.

During 2011, we operated our business at a loss.  Even though we were able to generate positive cash flow from operations, we will likely require external financing sources, including new bank borrowings and the issuance of equity securities, to fund our acquisition and growth capital expenditures.  However, to the extent we are unable to continue to finance growth externally, it will significantly impair our ability to grow.  We may need new capital to finance these activities.  Limitations on our access to capital will impair our ability to execute this strategy.  We recently have funded most of these activities with bank borrowings and repaid such debt through subsequent cash flow from operations and the issuance of equity. An inability to access the capital markets, particularly the equity markets, will impair our ability to execute this strategy and have a detrimental impact on our credit profile.

Our debt instruments may limit our financial flexibility and impair our financial condition.

Our credit agreement with Meridian contains restrictive covenants that may prevent us from engaging in certain transactions that we deem beneficial and that may be beneficial to us.  In addition, the Meridian credit agreement generally requires us to comply with various affirmative and negative covenants, including the maintenance of certain financial ratios and restrictions on (i) incurring additional debt; (ii) entering into mergers, consolidations and sales of assets; (iii) granting liens; (iv) declaring or paying dividends or making other distributions; and (v) entering into sale-leaseback transactions.   The instruments governing any future debt may contain similar or more restrictive restrictions.  Our ability to respond to changes in business and economic conditions and to obtain additional financing, if needed, may be restricted.

Our ability to successfully operate our business, and to allow for growth, is subject to a number of risks and uncertainties.  Similarly, we may not be able to successfully expand our business through acquiring or growing our assets, because of various factors, including economic and competitive factors beyond our control.  If we are unable to grow our business, or execute on our business plan, our credit profile is likely to be impaired and the market price of our common stock is likely to decline.

                Our ability to manage and grow our business effectively may be adversely affected if we lose key management or other key employees.

We depend on the continuing efforts of Frederick M. Pevow, Jr., our chief executive officer, president, secretary and treasurer.  The departure of Mr. Pevow could have a significant negative effect on our business, operating results, financial condition and on our ability to compete effectively in the marketplace.  Our ability to hire, train and retain qualified personnel, including accounting, business operations, finance, and other key back-office personnel, will continue to be important and will become more challenging as we grow and if energy industry market conditions remain positive.  When general industry conditions are good, the competition for experienced operational and field technicians increases as other energy and manufacturing companies’ needs for the same personnel increases.  Our ability to grow and perhaps even to continue our current level of service to our current customers will be adversely impacted if we are unable to successfully hire, train and retain these important personnel.

                Because of the natural decline in production from existing wells, our success depends on our ability to obtain new supplies of natural gas, which involves factors beyond our control. Any decrease in supplies of natural gas in our areas of operation could adversely affect our business and operating results.

Our gathering pipeline systems are dependent on the level of production from natural gas wells that supply our systems from which production will naturally decline over time.  As a result, our cash flows associated with these wells will also decline over time.  In order to maintain or increase through-put volume levels on our gathering and transportation pipeline systems, we must continually obtain new supplies.  The primary factors affecting our ability to obtain new supplies of natural gas and attract new customers to our assets are: the level of successful drilling activity near our systems and our ability to compete with other gathering and processing companies for volumes from successful new wells.

The level of natural gas drilling activity is dependent on economic and business factors beyond our control.  The primary factor that impacts drilling decisions is natural gas prices.  A sustained decline in natural gas prices could result in a decrease in exploration and development activities in the fields served by our gathering and transportation pipeline systems, which would lead to reduced utilization of these assets. 

Other factors that impact drilling and production decisions include producers’ capital budget limitations and the ability of producers to obtain necessary drilling and other governmental permits and regulatory changes.  For example, companion Senate and House bills to amend the Safe Drinking Water Act were introduced in Congress in June 2009.  The proposed legislation would require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process.  Hydraulic fracturing is utilized by wells drilled in the Barnett Shale served by our Hickory Creek Gathering System. 

The EPA is performing a study of the environmental impact of hydraulic fracturing, a process used by the U.S. oil and gas industry that involves the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas  and oil production in economic quantities.  Specifically, the EPA is reviewing the impact of hydraulic fracturing wastewater and stormwater on drinking water resources through the use of scenario evaluation, laboratory and case studies, and an analysis of existing data.  Certain environmental and other groups have suggested that additional federal, state and local laws and regulations may be needed to more closely regulate the hydraulic fracturing process.  Several states have adopted regulations that require operators to disclose the chemical constituents in hydraulic fracturing fluids, including Texas.  In addition, the EPA has announced that it will release initial study results during 2012 and an additional report during 2014.  We cannot predict whether any federal, state or local laws or regulations will be enacted regarding hydraulic fracturing, and, if so, what actions any such laws or regulations would require or prohibit.  The adoption of any future federal or state laws or implementing regulations imposing reporting obligations on, or otherwise limiting, the hydraulic fracturing process could result in a decrease in our customers’ exploration and production activities, resulting in lower volumes of natural gas production, which could result in a decline in the demand for our services.

As another example, following the well blowout and resulting oil spill in the Spring and Summer of 2010 at the BP Macondo Field offshore in the Gulf of Mexico, the U.S. government suspended the issuance of new drilling permits in the deepwater Gulf of Mexico.  In addition, drilling permits in shallower waters on the Continental Shelf in Federal Waters of the Gulf of Mexico now must comply with Notice to Lessees and Operators (“NTL”) 2010-NO5 and the NTL 2010-NO6 issued by the former Minerals Management Service, among other new federal regulations affecting offshore drilling.  We own and operate natural gas gathering systems located in federal waters of the Gulf of Mexico.  The adoption of any future federal or state laws or implementing regulations imposing reporting obligations on, or otherwise limiting, offshore drilling could result in a decrease in our customers’ exploration and production activities, resulting in lower volumes of natural gas production, which could result in a decline in the demand for our services.  See Item 1, Business – Water for more information.

Because of these and other factors, even if additional natural gas reserves exist in areas served by our assets, producers may choose not to develop those reserves.  If we were not able to obtain new supplies of natural gas to replace the natural decline in volumes from existing wells due to reductions in drilling activity or competition, through-put volumes on our pipelines and the utilization rates of our processing facilities would decline, which could have a material adverse effect on our business, results of operations and financial condition.

                Many of our customers’ drilling activity levels and spending for transportation on our pipeline system may be impacted by the current deterioration in natural gas prices and the credit markets.

Many of our customers finance their drilling activities through cash flow from operations, the incurrence of debt or the issuance of equity.  Recently, there has been a significant decline in the credit markets and the availability of credit.  Any combination of a reduction of cash flow resulting from declines in natural gas prices, a reduction in borrowing bases under reserve-based credit facilities and the lack of availability of debt or equity financing may result in a significant reduction in our customers’ spending for natural gas drilling activity, which could result in lower volumes being transported on our pipeline system.  A significant reduction in drilling activity could have a material adverse effect on our operations.

                In accordance with industry practice, we do not obtain independent evaluations of natural gas reserves dedicated to our gathering systems.  Accordingly, volumes of natural gas gathered on our gathering systems in the future could be less than we anticipate, which could adversely affect our business and operating results.

We do not obtain independent evaluations of natural gas reserves connected to our gathering systems due to the unwillingness of producers to provide reserve information as well as the cost of such evaluations.  Accordingly, we do not have estimates of total reserves dedicated to our systems or the anticipated lives of such reserves.  If the total reserves or estimated lives of the reserves connected to our gathering systems are less than we anticipate and we are unable to secure additional sources of natural gas, then the volumes of natural gas gathered on our gathering systems in the future could be less than we anticipate.  A decline in the volumes of natural gas gathered on our gathering systems could have an adverse effect on our business, results of operations and financial condition.

                If we fail to balance our purchases of natural gas our exposure to commodity price risk will increase.

We may not be successful in balancing our purchases of natural gas.  For example, even though we attempt to purchase and sell natural gas according to back-to-back contracts based on monthly index prices, we are still subject to intra-month increases and decreases in the price of natural gas if the amount of natural gas actually used by our customers in any given month differs materially from the amounts purchased by us at the beginning of the month.  In addition, upstream pipelines could fail to deliver promised volumes to us or deliver in excess of contracted volumes or a purchaser could purchase less than contracted volumes.  Any of these actions could cause an imbalance between our purchases and sales.  If our purchases and sales are not balanced, we will face increased exposure to commodity price risks and could have increased volatility in our operating income and working capital. 

                We may be burdened with significant pipeline abandonment liabilities.

Federal and state laws mandate certain rules and regulations related to the abandonment of pipelines and related facilities once the pipelines have ceased operations.  Certain of our agreements with producers offshore in the Gulf of Mexico and in state waters in Texas require us to incur all or part of the abandonment costs once production ceases from their leases.  Additionally, as noted above, NTL 2010-G05, the “Idle Iron Guidance,” establishes well abandonment and decommissioning requirements that are no longer tied to lease expiration.  The maturity and production decline of Gulf of Mexico oil and gas fields continues to cause an increase in the number of wells to be plugged and abandoned and platforms and pipelines to be decommissioned in accordance with such guidance.  The timing and costs of abandonment of offshore pipelines can vary widely based on certain factors outside of our control, including the amount of reserves dedicated to our pipelines, weather, the availability and costs incurred for transportation and diving and support operations.

During 2011, we established an estimated asset retirement obligation of $1,013,279.  The establishment of this obligation was necessary due to changes in our estimated abandonment dates, ongoing discussions with our customers and updated costs to retire these assets.  This liability will be accreted to the Company’s total undiscounted estimated liability over future periods until the date of such abandonment.

                We depend on certain key customers for a significant portion of our revenue and operating profit. The loss of, or reduction in, any of these key customers could adversely affect our business and operating results.

We rely on a limited number of customers for a significant portion of our sales volumes and sales revenue on our natural gas distribution pipelines.  These contracts have terms that range from an annual basis to multiple years.  As these contracts expire we will have to negotiate extension or renewals or replace the contracts on equally favorable terms with those of other customers, possibly requiring substantial capital expenditures to do so.  The loss of either of our contracts with Dart Container Corporation or Owens Corning when they expire could have a material adverse effect on our business, results of operations and financial condition, and possibly result in the need to abandon the associated pipelines.  The closure of or reduction of production in any of any of the industrial plants, including those owned by Tyson or Hydro Aluminum, served by our natural gas distribution pipelines, for economic or other reasons, would have a similar negative impact.

                To the extent that we intend to grow internally through construction of new, or modification of existing, facilities, we may not be able to manage that growth effectively, which could decrease our cash flow and adversely affect our results of operations.

A principal focus of our strategy is to continue to grow by expanding our business both internally and through acquisitions.  Our ability to grow internally will depend on a number of factors, some of which will be beyond our control.  In general, the construction of additions or modifications to our existing systems, and the construction of new midstream assets involve numerous regulatory, environmental, political and legal uncertainties beyond our control.  In addition, we may not be able to finance construction or modifications on satisfactory terms.  Any project that we undertake may not be completed on schedule, at budgeted cost or at all.  Construction may occur over an extended period, and we are not likely to receive a material increase in revenues related to such project until it is completed.  Moreover, our revenue may not increase immediately upon the completion of construction because the anticipated growth in gas production that the project was intended to capture does not materialize, our estimates of the growth in production prove inaccurate or for other reasons.  In addition, our ability to undertake to grow in this fashion will depend on our ability to hire, train, and retain qualified personnel to manage and operate these facilities when completed.

                A change in the level of regulation or the jurisdictional characterization of some of our assets or business activities by federal, state or local regulatory agencies could affect our operations and revenues.

Our gathering, transmission and distribution activities are intrastate in nature and generally exempt from regulation by the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act, the Natural Gas Policy Act of 1978 and other rules and regulations promulgated by FERC, but FERC regulation still affects our business and the markets for products derived from our business.  With the passage of the Energy Policy Act of 2005 (“EPACT 2005”), FERC has expanded its oversight of natural gas purchasers, natural gas sellers, gatherers, intrastate pipelines and shippers on FERC regulated pipelines by imposing new market monitoring and market transparency rules and rules prohibiting manipulative behavior.  In addition, EPACT 2005 substantially increased FERC’s penalty authority.  In recent years, FERC has adopted new rules requiring increased reporting by purchasers and sellers of natural gas, intrastate pipelines and gathering systems of certain information, and in 2009, FERC issued a notice of proposed rulemaking seeking comments on proposed increased transactional reporting requirements for intrastate pipelines.  We cannot predict the outcome of the rulemaking proceeding or how FERC will approach future matters such as pipeline rates and rules and policies that may affect purchases or sales of natural gas or rights of access to natural gas transportation capacity.

In addition, the distinction between FERC-regulated interstate transmission service, on one hand, and intrastate transmission or federally unregulated gathering services, on the other hand, is the subject of regular litigation at FERC, in the courts and of policy discussions at FERC.  In such circumstances, the classification and regulation of some of our gathering or our intrastate transportation pipelines may be subject to change based on future determinations by FERC, the courts or Congress.  Such a change could result in increased regulation by FERC, which could adversely affect our business.  Even without regulation by FERC, our operations may still be subject to regulation by various state agencies.  The applicable statutes and regulations generally require that our rates and terms and conditions of service provide no more than a fair return on the aggregate value of the facilities used to render such services.

Other state and local regulations also affect our business.  Our gathering pipelines are subject to ratable take and common purchaser statutes in states in which we operate.  Ratable take statutes generally require gatherers to take, without undue discrimination, oil or natural gas production that may be tendered to the gatherer for handling.  Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer.  These statutes restrict our right as an owner of gathering facilities to decide with whom we contract to purchase or transport natural gas.  Federal law leaves any economic regulation of natural gas gathering to the states.  The states in which we operate have adopted complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination.

Any new laws, rules, regulations or orders could result in additional compliance costs and/or requirements, which could adversely affect our business.  If we fail to comply with any new or existing laws, rules, regulations, laws or orders, we could be subject to administrative, civil and/or criminal penalties, or both, as well as increased operational requirements or prohibitions.

                We may be unable to integrate successfully the operations of future acquisitions with our operations, and we may not realize all the anticipated benefits of the past and any future acquisitions.

Integration of acquisitions with our business and operations is a complex, time consuming and costly process.  Failure to integrate acquisitions successfully with our business and operations in a timely manner may have a material adverse effect on our business, financial condition and results of operations.  We cannot assure you that we will achieve the desired profitability from past or future acquisitions.  In addition, failure to assimilate future acquisitions successfully could adversely affect our financial condition and results of operations.  Our acquisitions involve numerous risks, including:

·         operating a significantly larger combined organization and adding operations;

·         difficulties in the assimilation of the assets and operations of the acquired businesses, especially if the assets acquired are in a new business segment or geographic area;

·         the risk that natural gas reserves expected to support the acquired assets may not be of the anticipated magnitude or may not be developed as anticipated;

·         the loss of significant producers or markets or key employees from the acquired businesses;

·         the diversion of management’s attention from other business concerns;

·         the failure to realize expected profitability, growth or synergies and cost savings;

·         the risk that customers or plants served by the pipelines that we acquire will not be satisfied with the change in ownership of the pipeline serving their facility;

·         properly assessing and managing environmental compliance;

·         coordinating geographically disparate organizations, systems, and facilities;

·         the assumption of unknown liabilities for which we may not be indemnified by the seller or for which our indemnity may be inadequate;

·         the decrease in our liquidity as a result of our using a significant portion of our available cash or borrowing capacity; and

·         coordinating or consolidating corporate and administrative functions.

Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition.  If we consummate any future acquisition, our capitalization and results of operation may change significantly, and you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future acquisitions.

                Our industry is highly competitive, and increased competitive pressure could adversely affect our business and operating results.

We compete with similar enterprises in each of our areas of operations.  Some of our competitors are large oil, natural gas, gathering and processing, natural gas pipeline companies and natural gas utilities that have greater financial resources and access to supplies of natural gas than we do.  Competitors may establish new connections with pipeline systems that would create additional competition for services that we provide to our customers.  Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors.

                Any reduction in the capacity of, or the allocations to, our shippers in interconnecting, third-party pipelines could cause a reduction of volumes transported in our pipelines, which would adversely affect our revenues and cash flow.

Users of our pipelines are dependent upon connections to and from third-party pipelines to receive and deliver natural gas.  Any reduction in the capacities of these interconnecting pipelines due to testing, line repair, reduced operating pressures or other causes could result in reduced volumes being transported in our pipelines.  Similarly, if additional shippers begin transporting volumes of natural gas over interconnecting pipelines, the allocations to existing shippers in these pipelines could be reduced, which could also reduce volumes transported in our pipelines.  Any reduction in volumes transported in our pipelines would adversely affect our revenue and cash flow.

                We are exposed to the credit risks of our key customers, and any material nonpayment or nonperformance by our key customers could adversely affect our cash flow and results of operations.

We are subject to risks of loss resulting from nonpayment or nonperformance by our customers.  Many of our customers finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity.  The combination of reduction of cash flow resulting from declines in commodity prices, a reduction in borrowing bases under reserve based credit facilities (resulting from a decline in commodity prices) and the lack of availability of debt or equity financing may result in a significant reduction in our customers’ liquidity and ability to make payment or perform on their obligations to us.  Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us.

Energy commodity transportation activities involve numerous risks, some of which may not be fully covered by insurance, that may result in accidents or otherwise adversely affect our operations and financial condition.

There are a variety of hazards and operating risks inherent to natural gas transmission activities — such as leaks, explosions and mechanical problems — that could result in substantial financial losses.  In addition, these risks could result in serious injury and loss of human life, significant damage to property and natural resources, environmental pollution and impairment of operations, any of which also could result in substantial financial losses.  For pipeline and storage assets located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of damage resulting from these risks could be greater.  Incidents that cause an interruption of service, such as when unrelated third party’s construction damages a pipeline or a newly completed expansion experiences a weld failure, may negatively impact our revenues and earnings while the affected asset is temporarily out of service.  In addition, a natural disaster such as a hurricane or other hazard affecting the areas in which we operate could have a material adverse effect on our operations.  We are also not insured against all below ground property damage and business interruptions that might occur.  Our business operations in federal and state waters of the Gulf of Mexico experienced significant damage as the result of Hurricane Ike in 2008 and there is no assurance that another significant hurricane might not cause even more damage.  If losses in excess of our insurance coverage were to occur, they could have a material adverse effect on our business, financial condition and results of operations.

Increased regulatory requirements relating to the integrity of our pipelines and other assets will require us to spend additional money to comply with these requirements.

We are subject to extensive laws and regulations related to asset integrity.  The U.S. Department of Transportation (“DOT”), for example, regulates pipelines in the areas of testing, education, training and communication.  The U.S. DOT issued final rules (effective February 2004 with respect to natural gas pipelines) requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines and take measures to protect pipeline segments located in what the rules refer to as “high consequence areas.”  The ultimate costs of compliance with the integrity management rules are difficult to predict.  The majority of the costs to comply with the rules are associated with asset integrity testing and the repairs found to be necessary.  Changes such as advances of inspection tools, identification of additional threats to integrity and changes to the amount of pipeline determined to be located in “high consequence areas” can have a significant impact on the costs to perform integrity testing and repairs.  We plan to continue our integrity testing programs to assess and maintain the integrity of our existing and future assets as required by the U.S. DOT rules.  The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our assets.

Further, additional laws and regulations that may be enacted in the future or a new interpretation of existing laws and regulations could significantly increase the amount of these expenditures.  Federal pipeline enforcement has also seen increased coordination between the EPA and the Pipeline and Hazardous Materials Safety Administration (PHMSA), possibly in response to more recent pipeline spills and failures on the North Slope in Alaska, in San Bruno, California, and into the Yellowstone River, to name a few.  In response to legislative mandates, PHMSA has been engaged for the past several years in waves of rule-making to address the safety of oil and gas pipelines.  Some of these new rules are in effect. Several proposed rules are pending finalization.  There can be no assurance as to the amount or timing of future expenditures for asset integrity regulation, and actual future expenditures may be different from the amounts we currently anticipate.  Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not deemed by regulators to be fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and prospects.

                Failure of the gas that we ship on our pipelines to meet the specifications of interconnecting interstate pipelines could result in curtailments by the interstate pipelines.

The markets to which the shippers on our pipelines ship natural gas include interstate pipelines.  These interstate pipelines establish specifications for the natural gas that they are willing to accept, which include requirements such as hydrocarbon dewpoint, temperature, and foreign content including water, sulfur, carbon dioxide and hydrogen sulfide.  These specifications vary by interstate pipeline.  If the total mix of natural gas shipped by the shippers on our pipeline fails to meet the specifications of a particular interstate pipeline, it may refuse to accept all or a part of the natural gas scheduled for delivery to it.  In those circumstances, we may be required to find alternative markets for that gas or to shut-in the producers of the non-conforming gas, potentially reducing our through-put volumes or revenues.

                We do not own all of the land on which our pipelines and facilities have been constructed, and we are therefore subject to the possibility of increased costs or the inability to retain necessary land use.

We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for specified periods of time.  Many of these rights-of-way are perpetual in duration; others have terms ranging from five to ten years.  Many are subject to rights of reversion in the case of non-utilization for periods ranging from one to three years.  Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations and financial condition.

In addition, the construction of additions to our existing gathering, transmission and distribution assets may require us to obtain new rights-of-way prior to constructing new pipelines.  We may be unable to obtain such rights-of-way to connect new natural gas supplies to our existing gathering lines or to capitalize on other attractive expansion opportunities.  If the cost of obtaining new rights-of-way increases, our cash flows and growth opportunities could be adversely affected.

                We may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental regulations or an accidental release of hazardous substances into the environment.

Our operations are subject to stringent and complex federal, state and local environmental laws and regulations governing, among other things, air emissions, wastewater discharges, the use, management and disposal of hazardous and nonhazardous materials and wastes, and the cleanup of contamination.  Noncompliance with such laws and regulations, or incidents resulting in environmental releases, could cause us to incur substantial costs, penalties, fines and other criminal sanctions, third party claims for personal injury or property damage, investments to retrofit or upgrade our facilities and programs, or curtailment of operations.  Certain environmental statutes, including the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) and comparable state laws, impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed or otherwise released.

There is inherent risk of the incurrence of environmental costs and liabilities in our business due to the necessity of handling natural gas, air emissions related to our operations and historical industry operations and waste disposal practices.  For example, an accidental release from one of our pipelines or processing facilities could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage, and fines or penalties for related violations of environmental laws or regulations.  Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary.  Although we maintain general liability and pollution liability insurance, these policies are subject to exceptions and coverage limits.  We maintain limited environmental liability insurance covering named locations and environmental risks associated with contract services for producing properties.  We could be materially and adversely affected by an enforcement proceeding or a claim that is not covered or is only partially covered by insurance.

Because our business depends on the level of activity in the oil and natural gas industry, existing or future laws, regulations, treaties, or international agreements that impose additional restrictions on the industry affect our business.  Regulators are becoming more focused on air emissions from oil and gas operations including volatile organic compounds, hazardous air pollutants, and greenhouse gases.  We cannot be certain that identification of presently unidentified conditions, more vigorous enforcement by regulatory agencies, enactment of more stringent laws and regulations, or other unanticipated events will not arise in the future and give rise to material environmental liabilities that could have a material adverse effect on our business, financial condition or results of operations.  

We are subject to risks associated with climate change.

There is a growing belief that emissions of greenhouse gases (GHGs) may be linked to climate change.  Climate change and the costs that may be associated with its impacts and the regulation of GHGs have the potential to affect our business in many ways.  The focus on GHGs and climate change, including incentives to conserve energy or use alternative energy sources, could have a negative impact on our business if existing or future laws, regulations, treaties, or international agreements reduce the worldwide demand for oil and natural gas or otherwise result in reduced economic activity generally.  In addition, such laws, regulations, treaties, or international agreements could result in increased compliance costs, capital spending requirements, or additional operating restrictions, which may have a negative impact on our business.  In addition to potential impacts on our business directly or indirectly resulting from climate change legislation or regulations, our business also could be negatively affected by climate change-related physical changes or changes in weather patterns, all of which can create financial risks.

Our common stock may be affected by limited trading volume and may fluctuate significantly.

Currently our common stock is quoted on the OTC Bulletin Board and the trading volume developed to date is limited by the fact that many major institutional investment funds and mutual funds, as well as many individual investors, follow a policy of not investing in OTC Bulletin Board stocks and, moreover, certain major brokerage firms restrict their brokers from recommending OTC Bulletin Board stocks because they are considered speculative, volatile and thinly traded.  The OTC Bulletin Board is an inter-dealer market and is much less regulated than the major stock exchanges, and trading in our common stock is potentially subject to abuses, volatilities and shorting.

In addition, there has been a limited public market for our common stock, and an active trading market for our common stock may not develop.  This could reduce our stockholders’ ability to sell our common stock in short time periods, or possibly at all.  Our common stock has experienced, and is likely to experience in the future, significant price and volume fluctuations which could reduce the market price of our common stock without regard to our operating performance.  In addition, we believe that factors such as quarterly fluctuations in our financial results and changes in the overall economy or the condition of the financial markets could cause the price of our common stock to fluctuate substantially.

We are authorized to issue “blank check” preferred stock, which can be issued without stockholder approval and may adversely affect the rights of holders of our common stock.

We are authorized to issue 10,000 shares of preferred stock.  Our board of directors is authorized under our restated certificate of incorporation, as amended, to provide for the issuance of shares of preferred stock by resolution, and upon filing a certificate of designations under Delaware law, to fix the designation, powers, preferences and rights of the shares of each such series and the qualifications, limitations or restrictions thereof, without any further vote or action by the stockholders.  Any shares of preferred stock so issued are likely to have priority over our common stock with respect to dividend and/or liquidation rights.  In the event of issuance, the preferred stock could be utilized, under certain circumstances, as a method of discouraging, delaying or preventing a change in control, which could have the effect of discouraging bids for us and thereby prevent stockholders from receiving the maximum value for their shares.  No preferred shares are issued and outstanding as of March 30, 2012.

Delaware law may inhibit a takeover of us that our stockholders may consider favorable.

Provisions of Delaware law, such as its business combination statute, may have the effect of delaying, deferring or preventing a change in control of us, even if such a transaction would have significant benefits to our stockholders.  As a result, these provisions could limit the price some investors might be willing to pay in the future for shares of our common stock.

ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

This item is not applicable for smaller reporting companies such as Gateway.

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

See index to Consolidated Financial Statements beginning on page F-1 of this Annual Report on Form 10-K.

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

None

ITEM 9A.  CONTROLS AND PROCEDURES.

Disclosure Controls and Procedures

Based on their evaluation as of the end of the period covered by this Annual Report on Form 10-K, Gateway’s principal executive officer and principal financial officer concluded that the Company’s disclosure controls and procedures as defined in Rule 13a-15(e) and 15d-15(e)  under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) were effective for the year ended December 31, 2011 such that the information relating to Gateway required to be disclosed in reports that it files or submits under the Exchange Act (1) was recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms, and (2) was accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

Management’s Report on Internal Control over Financial Reporting

                Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Our internal control system is designed to provide reasonable assurance to our management and board of directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles. Our internal control over financial reporting includes those policies and procedures that:

·         Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;

·         Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and

·         Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2011.  In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework.  Based on management's assessment and those criteria, management concluded internal controls over financial reporting were effective as of December 31, 2011.  

This annual report does not include an attestation report of the Company's independent registered public accounting firm regarding internal control over financial reporting.  Management's report was not subject to attestation by the Company’s registered public accounting firm pursuant to the permanent exemption by the Securities and Exchange Commission that permits the Company to provide only management's report in this annual report.

Changes in Internal Control over Financial Reporting

As reported in our Form 8-K filed with the Securities Exchange Commission on March 7, 2011, on March 1, 2011, Jill R. Marlatt, our Controller, Treasurer, Secretary and Principal Financial Officer, tendered her resignation from all of the foregoing positions, effective March 18, 2011.  On March 2, 2011, the Board of Directors of the Company appointed Frederick M. Pevow as Interim Secretary and Treasurer of the Company (which offices are in addition to his previously existing offices of Chief Executive Officer and President) until such time as the Board of Directors can identify a permanent replacement for Ms. Marlatt.

In connection with Mr. Pevow’s above noted officer position appointments, he also assumed responsibility as our Principal Financial Officer, in addition to his previously existing responsibility as our Principal Executive Officer.  In order to maintain appropriate controls and procedures in place upon Ms. Marlatt’s departure to ensure that information required to be disclosed in our reports filed under the Securities Exchange Act of 1934, as amended, were recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission's rules and forms, and that such information was 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 during our year ended December 31, 2011, the Company engaged third party financial reporting consultants to assist in the supervision of its accounting staff, provide oversight of entries recorded and assist management in the preparation of the Company’s consolidated financial statements in accordance with GAAP and the rules and regulations promulgated by the Securities and Exchange Commission.

ITEM 9B.  OTHER INFORMATION.

None

PART III

ITEM 10.   DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.

 Incorporated by reference to the Gateway Energy Corporation Proxy Statement for the 2012 Annual Meeting of Stockholders, under the captions “ELECTION OF DIRECTORS,” “EXECUTIVE OFFICERS OF THE COMPANY” “GOVERNANCE OF THE COMPANY” and “SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE”.

ITEM 11.   EXECUTIVE COMPENSATION.

Incorporated by reference to the Gateway Energy Corporation Proxy Statement for the 2012 Annual Meeting of Stockholders, under the caption “EXECUTIVE COMPENSATION.”

ITEM 12.   SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND

RELATED STOCKHOLDER MATTERS.

Incorporated by reference to the Gateway Energy Corporation Proxy Statement for the 2012 Annual Meeting of Stockholders, under the captions “SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT”.

Securities Authorized for Issuance Under Equity Compensation Plans

            The following information is presented as of December 31, 2011:

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

Incorporated by reference to the Gateway Energy Corporation Proxy Statement for the 2012 Annual Meeting of Stockholders, under the caption “CERTAIN RELATIONSHIPS AND TRANSACTIONS WITH RELATED PERSONS” and “GOVERNANCE OF THE COMPANY”.

ITEM 14.   PRINCIPAL ACCOUNTANT FEES AND SERVICES.

                Incorporated by reference to the Gateway Energy Corporation Proxy Statement for the 2012 Annual Meeting of Stockholders, under the caption “INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM.”

PART IV

ITEM 15.   EXHIBITS, FINANCIAL STATEMENT SCHEDULES.

The following Exhibits are filed herewith or incorporated herein by reference.

Exhibit                                           Description of Document

 *    Filed herewith

**   Furnished herewith. Pursuant to Rule 406T of Regulation S-T, the Interactive Data Files on Exhibit 101 hereto are deemed not filed or part of any registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, are deemed not filed for purposes of Section 18 of the Securities and Exchange Act of 1934, and otherwise are not subject to liability under those sections.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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

(Registrant)

By:         /s/Frederick M. Pevow, Jr  .

                                                                                 President & Chief Executive Officer, Secretary and Treasurer

Date:    March 30, 2012

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

GATEWAY ENERGY CORPORATION

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

All financial schedules have been omitted as required information is either not applicable or has been included in the financial statements or notes to the financial statements.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Shareholders

Gateway Energy Corporation

We have audited the accompanying consolidated balance sheets of Gateway Energy Corporation and Subsidiaries (the “Company”) as of December 31, 2011 and 2010 and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the years in the two year period ended December 31, 2011.  These financial statements are the responsibility of the Company's management.  Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purposes of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Gateway Energy Corporation and Subsidiaries as of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the years in the two year period ended December 31, 2011 in conformity with U.S. generally accepted accounting principles.

/s/ Pannell Kerr Forster of Texas, P.C.

Houston, Texas

March 30, 2012

                                                                                                        GATEWAY ENERGY CORPORATION AND SUBSIDIARIES

                                                                                                                        CONSOLIDATED BALANCE SHEETS

GATEWAY ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

                                                                                GATEWAY ENERGY CORPORATION AND SUBSIDIARIES

                                                                           CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

GATEWAY ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(1)     Nature of Business

Gateway Energy Corporation (the “Company,” “Gateway,” “we,” or “our”), a Delaware corporation, was incorporated in 1960 and entered its current business in 1992.  Gateway’s common stock is traded in the over-the-counter market on the bulletin board section under the symbol GNRG.  Gateway is engaged in the midstream natural gas business.  We own and operate natural gas distribution, gathering and transportation pipeline 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, Gateway Commerce LLC and CEU TX NPI, L.L.C.  Gateway-Madisonville Pipeline, L.L.C. is 67% owned by Gateway Pipeline Company and 33% owned by Gateway Processing Company.  Access to our annual reports on Form 10-K, quarterly reports on Form 10-Q, our Code of Ethics and current reports on Form 8-K are available at Gateway’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. 

(2)     Summary of Significant Accounting Policies

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

Principles of Consolidation

The Company consolidates the financial statements of its majority-owned and wholly-owned subsidiaries.  All significant intercompany transactions have been eliminated in consolidation.   

The accompanying consolidated financial statements have been prepared by the Company.  In the opinion of management, such financial statements reflect all adjustments necessary for a fair presentation of the financial position and results of operations in accordance with U.S. generally accepted accounting principles.

 Reclassifications 

Certain reclassifications have been made to the December 31, 2010 financial statements to conform to the current period presentation.  These reclassifications had no effect on the total assets, liabilities, stockholders’ equity or net loss for the year ended December 31, 2010.

Use of Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles (“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 our 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.  Onshore transportation revenues are recognized at the redelivery point, which is the point at which another party takes physical custody of the natural gas or liquid hydrocarbons.  Offshore transportation revenues are recognized at the receipt point.

Cash Equivalents

For purposes of the consolidated statements of cash flows, we consider all highly liquid debt instruments purchased with original maturities of three months or less to be cash equivalents.

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 year ended December 31, 2011, three companies, Cokinos Energy Corporation, ETC Marketing, Ltd., and Shell Energy North America supplied 35.3%, 32.4% and 32.3%, respectively, of our total natural gas purchases.  During the year ended December 31, 2010, Shell Energy North America supplied 100% of our total natural gas purchases. 

                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 years ended December 31, 2011 and 2010 are as follows:  

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

                Deposits

            At December 31, 2010, we had deposited $250,000 with a supplier as collateral for gas purchase costs.  This deposit was returned in 2011.

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 year ended December 31, 2011, depreciation, depletion and amortization expense was $623,062, as compared to $734,721 for the year ended December 31, 2010. 

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.  Impairments of long-lived assets recorded during the years ended December 31, 2011 and 2010 was $3,365,168 and $1,865,396, respectively.  

The following tables represent gross intangible assets, accumulated amortization and amortization expense for the year ended December 31, 2011, and estimated amortization expense for the next 5 years:

The weighted average remaining amortization period is approximately 9 years for contract intangible assets.

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 certain 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.

During 2011, the Company 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.

The following table describes changes to the Company’s asset retirement obligation liability for the year ended December 31, 2011:

            Income Taxes

We compute income taxes using the asset and liability method whereby deferred tax assets are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis.  Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled.  The effect on deferred tax assets and liabilities from a change in tax rates is recognized in income in the period that includes the enactment date.  A valuation allowance is established against such assets where management is unable to conclude more likely than not that such asset will be realized.

Stock-Based Compensation

The Company’s 2007 Equity Incentive Plan (“2007 Plan”) provides for stock-based compensation for officers, employees and non-employee directors.  We account for stock-based compensation under the provisions of ASC Topic 718, “Compensation – Stock Compensation” (“ASC Topic 718”).  The options generally vest ratably over three years and expire between five and ten years.  The restricted stock generally vests ratably between three months and three years.

Compensation expense related to non-qualified stock options and restricted stock was $73,695 for the year ended December 31, 2011 compared to compensation expense of $6,538 for the year ended December 31, 2010.  We view all awards of stock-based compensation as a single award with an expected life equal to the average expected life of component awards and amortize the fair value of the award over the requisite service period.

Compensation expense and forfeiture adjustments related solely to stock options was $15,759 and $(2,364), respectively, for the year ended December 31, 2011, compared to $27,880 and $(49,676) in compensation expense and forfeiture adjustments, respectively, for the year ended December 31, 2010.  At December 31, 2011, there was $38,153 of total unrecognized compensation expense related to unvested stock option awards which is expected to be recognized over a remaining weighted-average period of approximately two years. 

The fair value of each option award is estimated on the date of grant using the Black-Scholes option-pricing model. We use the Black-Scholes option pricing model to compute the fair value of stock options, which requires us to make the following assumptions:

·   The risk-free interest rate is based on the five-year Treasury bond at date of grant.

·   The dividend yield on our common stock is assumed to be zero since we do not pay dividends and have no current plans to do so in the future.

·   The market price volatility of our common stock is based on daily, historical prices for the last three years.

·   The term of the grants is based on the simplified method as described in ASC Topic 718. 

In addition, we estimate a forfeiture rate at the inception of the option grant based on historical data and adjusts this prospectively as new information regarding forfeitures becomes available.

We receive a tax deduction for certain stock option exercises during the period the options are exercised, generally for the excess of the value of the stock over the strike price received on the date of exercise.  In addition, we receive an additional tax deduction when restricted stock vests at a higher value than the value used to recognize compensation expense at the date of grant.  We record these deductions as a tax asset with a corresponding amount recorded as additional paid-in capital when we can receive a tax cash savings from these awards.  Due to Gateway having significant unused net operating-loss carry forwards, we are deferring the recording of this tax benefit until such tax savings is realized.

Compensation expense for restricted stock is recognized on a straight-line basis over the vesting period.  We recognized $60,300 and $28,334 in net compensation expense related to restricted stock grants for the years ended December 31, 2011 and December 31, 2010, respectively.  Compensation expense related to restricted stock grants is based upon the market value of the shares on the date of the grant.  As of December 31, 2011, unrecognized compensation cost related to restricted stock awards was $95,811, which is expected to be recognized over the remaining weighted average period of approximately two years.

Financial Instruments

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 term note 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.

Earnings Per Share

Basic earnings per share is computed by dividing net earnings or net loss by the weighted average number of common shares outstanding during the period.  Diluted earnings per share is computed by dividing net earnings or net 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 years ended December 31, 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.

Accounting Pronouncements and Recent Regulatory Developments

None of the Accounting Standards Updates (ASU) that the Company adopted and that became effective January 1, 2011, had a material impact on its consolidated financial statements.

ASU No. 2011-04

On May 12, 2011, the FASB issued ASU No. 2011-04, “Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs.”  This ASU amends U.S. generally accepted accounting principles (U.S. GAAP) and results in a consistent definition of fair value and common requirements for measurement of and disclosure about fair value between U.S. GAAP and international financial reporting standards (IFRS).  The amendments in this ASU change the wording used to describe many of the requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements; however, the amendment’s requirements do not extend the use of fair value accounting, and for many of the requirements, the FASB did not intend for the amendments to result in a change in the application of the requirements in the “Fair Value Measurement” Topic of the Codification.  Additionally, ASU No. 2011-04 includes some enhanced disclosure requirements, including an expansion of the information required for Level 3 fair value measurements.  For the Company, ASU No. 2011-04 was effective January 1, 2012, and the adoption of this ASU is not expected to have a material impact on its consolidated financial statements.

ASU Nos. 2011-05 and 2011-12

On June 16, 2011, the FASB issued ASU No. 2011-05, “Comprehensive Income (Topic 220): Presentation of Comprehensive Income.”  This ASU eliminates the current option to report other comprehensive income and its components in the statement of changes in equity.  An entity can elect to present items of net income and other comprehensive income in one continuous statement or in two separate, but consecutive, statements.

ASU No. 2011-05 also requires reclassifications of items out of accumulated other comprehensive income to net income to be measured and presented by income statement line item in both the statement where net income is presented and the statement where other comprehensive income is presented.  However, on December 23, 2011, the FASB issued ASU No. 2011-12, “Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05” to defer this new requirement.  For us, both ASU No. 2011-05 and ASU No. 2011-12 were effective January 1, 2012.  Since these ASUs pertain to presentation and disclosure requirements only, the adoption of these ASUs is not expected to have a material impact on the Company’s consolidated financial statements.