UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C.  20549

 FORM 10-Q

[X]  QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

 OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2011

OR

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

For the transition period from

 __________to __________

                                  Commission File No.     000-06404                                  

GATEWAY ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

1415 Louisiana Street, Suite 4100

Houston, TX  77002

(Address of principal executive offices)

(713) 336-0844

(Registrant's telephone number)

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes  X  No ___  

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

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

As of August 16, 2011, the registrant had 23,564,185 shares of its common stock outstanding.

GATEWAY ENERGY CORPORATION AND SUBSIDIARIES

INDEX TO QUARTERLY REPORT

ON FORM 10-Q

Part  I – Financial Information

ITEM 1.     FINANCIAL STATEMENTS

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

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

  (1)  Interim Financial Information

Business and Organization

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

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

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

                Basis of Presentation

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

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

                Glossary

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

 (2)  Summary of Significant Accounting Policies and Estimates

                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, amortization of deferred loan costs, deferred tax valuation allowance, valuation of assumed liabilities, intangible lives, impairment and valuation of the fair value of long-lived assets, purchase price allocations and valuation of stock based transactions.  Actual results could differ from those estimates.

                Revenue Recognition

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

                Concentrations of Credit Risk

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

                During the three months ended June 30, 2011, three companies, ETC Marketing, Ltd., Cokinos Energy Corporation  and Shell Energy North America L.P. (“Shell”) supplied 36%, 35% and 29%, respectively, and during the six months ended June 30, 2011, these companies supplied 19%, 19% and 62%, respectively, of the total natural gas purchased by the Company during these periods.  During the three and six months ended June 30, 2010, Shell supplied 100% of the total natural gas purchased by the Company. 

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

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

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

 (3)  Business Combinations

                Acquisition of Hickory Creek Gathering System

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

                Acquisition of Pipeline from Laser Midstream

On September 22, 2010, Gateway entered into an Asset Sales Agreement with Laser Pipeline Company, LP (“Laser”) pursuant to which it agreed to acquire from Laser four pipelines and related assets for $1,100,000 in cash.  Transfer of ownership occurred and consolidation of the pipelines began on the closing date of October 18, 2010.  The transaction was accounted for in accordance with FASB ASC Topic 805 “Business Combinations”.  The Company recognized $75,839 and $53,401 in revenue and operating margin, respectively, for the three months ended June 30, 2011, and $155,353 and $109,171 in revenue and operating margin, respectively, for the six months ended June 30, 2011, from these assets.  

                Pro Forma Results of Operations

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

For the Three Months Ended June 30, 2010

For the Six Months Ended June 30, 2010

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

 (4)  Stock-Based Compensation Plans

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

During the six months ended June 30, 2011, the Company issued 318,751 shares of restricted stock to its non-employee directors.  During the six months ended June 30, 2011, the Company had forfeitures of 75,000 unvested stock options and 16,667 shares of unvested restricted stock.  As of June 30, 2011, 287,778 shares of the Company’s common stock were issuable under outstanding stock option grants under the 2007 Plan (which is in addition to 40,000 shares issuable under outstanding stock option grants under the Company’s former 1998 Stock Option Plans).  The Company also has 568,749 shares of unvested restricted stock outstanding under the 2007 Plan.  As of June 30, 2011, there are 1,093,473 shares available for issuance under future grants of awards under the 2007 Plan.

Total stock-based compensation cost was $16,859 and $(48,713) for the three months ended June 30, 2011 and 2010, respectively, and $24,734 and $(30,000) for the six months ended June 30, 2011 and 2010, respectively.  The Company considers all awards of stock-based compensation as a single award with an expected life equal to the average expected life of component awards and amortizes the fair value of the award over the requisite service period. 

Compensation expense and forfeiture adjustments related solely to stock options was $2,760 and $(1,342), respectively, for the three months ended June 30, 2011, compared to compensation expense and forfeiture adjustments of $3,576 and $(52,290), respectively, for the three months ended June 30, 2010.  For the six months ended June 30, 2011, compensation expense and forfeiture adjustments were $6,239 and $(2,364), respectively, compared to compensation expense and forfeiture adjustments of $22,290 and $(52,290), respectively, for the six months ended June 30, 2010.   At June 30, 2011, there was $20,782 of total unrecognized compensation expense related to unvested stock option awards which is expected to be recognized over a remaining weighted-average period of two years.

                The following table represents stock option activity for the six months ended June 30, 2011:

The market value of the Company’s common stock, as quoted on the OTCBB, on June 30, 2011 was $0.19 per share.

Compensation expense for restricted stock is recognized on a straight-line basis over the vesting period.  The Company recognized $15,441 and $20,858 in compensation expense related to restricted stock grants during the three and six months ended June 30, 2011, respectively.  The Company had no compensation expense related to restricted stock grants during the three and six months ended June 30, 2010.  Compensation expense related to restricted stock grants is based upon the market value of the shares on the date of the grant.  As of June 30, 2011, unrecognized compensation cost related to restricted stock awards was $109,595, which is expected to be recognized over the remaining weighted-average period of two years.

                The following table represents restricted stock activity for the six months ended June 30, 2011:

 (5)  Debt 

                Trade Notes Payable

During 2010, the Company executed premium finance agreements for its insurance premiums.  The total original principal amount of the notes issued in connection with these agreements was $428,367, with an interest rate of 4.95%.  The notes require monthly principal and interest payments.  The amount of the monthly payment varies depending on any changes in coverage and policy renewal periods. As of June 30, 2011, there was $124,951 outstanding under these notes.

GATEWAY ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2011

(Unaudited)

 (6)  Commitments and Contingencies

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

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

                Critical Accounting Policies

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

                Use of Estimates

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

                Revenue Recognition Policy

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

                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.

The Henry Hub monthly, INSIDE FERC price for natural gas (as quoted in the Platts Gas Daily Price Guide) during the three and six months ended June 30, 2011, averaged $4.32 and $4.21 per MMBtu, compared to $4.28 and $4.79 for the comparable periods of the prior year.  

                Results for the three and six months ended June 30, 2011 and 2010      

Revenues 

Our total revenues were $1,880,132 for the three months ended June 30, 2011, which represented an increase of $84,169 from the $1,795,963 of total revenues we recognized for the three months ended June 30, 2010.  During the three months ended June 30, 2011, revenues from sales of gas on our Waxahachie distribution system increased approximately $160,000 as compared to the same period for the prior year.  An approximate 8% increase in sales volumes, to 3,006 MMBtu/d, at Waxahachie accounted for an approximate $93,000 increase in revenues.  Higher gas prices contributed an additional $66,000 of revenue, however this effect was largely offset by increases in the cost of purchased gas, as volumes are bought and sold pursuant to “back-to-back” contracts based on monthly price indices.  During the three months ended June 30, 2011, our transportation revenues decreased by $90,403 as compared to the same period of the prior year.  Revenues of $75,839 from our newly acquired Laser operations were offset by net decreases of $166,242 attributable to production declines on natural gas wells connected to our gathering systems.  We believe that transportation revenues will eventually increase on some of our gathering systems due to new drilling and workover activities, but doubt meaningful activities will occur during the remainder of 2011.  Revenues from reimbursable costs and other revenue was relatively flat for the three months ended June 30, 2011, compared to the three months ended June 30, 2010.

Our total revenues were $3,644,265 for the six months ended June 30, 2011, which represented a decrease of $110,198 from the $3,754,463 of total revenues we recognized for the six months ended June 30, 2010.  During the six months ended June 30, 2011, revenues from sales of gas on our Waxahachie distribution system were relatively flat as compared to the same period for the prior year. An approximate 11% increase in sales volumes to 2,986 MMBtu/d at Waxahachie accounted for an approximate $277,000 increase in revenues.  The higher revenues from increased volumes were offset by a decline in the gas sales price on our Waxahachie system. 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.  During the six months ended June 30, 2011, our transportation revenues decreased by approximately $128,000 as compared to the same period of the prior year.  Revenues of $155,353 from our newly acquired Laser operations were offset by net decreases of $283,538 attributable to production declines on natural gas wells connected to our gathering systems.  Revenues from reimbursable costs and other revenue was relatively flat for the six months ended June 30, 2011, compared to the six months ended June 30, 2010.

                Operating Margin

Operating margin, which we define as fee revenues from the transportation of natural gas, plus revenues from the sale of natural gas net of the cost of purchased gas, less operating and maintenance expenses and reimbursable costs generated by our pipeline systems, was $525,274 for the three months ended June 30, 2011, which represented a decrease of $23,578 from the $548,852 of operating margin we recognized for the three months ended June 30, 2010.  Our newly acquired natural gas distribution operations from Laser contributed $65,655 to operating margin for the current period.  In addition, the Waxahachie distribution system generated a quarter-over-quarter increase of $41,626 in operating margin contribution to $173,985 for the current period.  Increases in operating margin on the Waxahachie system primarily consisted of $11,962 attributable to increased sales volumes to industrial customers and $29,113 attributable to increased gross margins per unit due to a new gas purchase contract, which expires on February 29, 2012.

Operating margin contribution from the Hickory Creek, Madisonville, and all Gulf of Mexico gathering systems was $285,634 for the three months ended June 30, 2011, which represented a decrease of an aggregate $130,854 from the prior period.  The decreases in operating margin on these gathering systems were attributable to the aforementioned production declines from gas wells connected to these systems.  Sizable production declines from the wells connected to our Hickory Creek gathering system are typical of newly fractured horizontal wells located in the Barnett Shale.  However, the rate of decline from wells connected to our Hickory Creek gathering system should decrease over time.  The Madisonville pipeline is currently dormant due to lack of production from the Madisonville Field.  We are evaluating alternative uses for the Madisonville pipeline in the event the Madisonville Field does not resume production.  Production volumes connected to our Gulf of Mexico gathering systems are expected to continue to decline for the remainder of 2011. Operating margin from the nine Gulf of Mexico gathering systems should not correspondingly decline with production volumes for the second half of 2011, however, as we are now billing base cost plus fees on three of these systems.  Customers in the Gulf of Mexico have also informed us of preliminary plans to drill at least one development well and perform workovers in 2012.

Operating margin was $1,012,361 for the six months ended June 30, 2011, which represented a decrease of $18,837 from the $1,031,198 of operating margin we recognized for the six months ended June 30, 2010.  Our newly acquired natural gas distribution operations from Laser contributed $121,425 to operating margin for the current period.  In addition, the Waxahachie distribution system generated a period-over-period increase of $76,409 in operating margin contribution to $333,748 for the current period.  We expect a similar operating margin on the former Laser and Waxahachie distribution systems for the second half of 2011 as for the first half of 2011.  Operating margin contribution from the Hickory Creek, Madisonville and all Gulf of Mexico gathering systems was $557,188 for the six months ended June 30, 2011, which represented a decrease of an aggregate $216,669 from the prior period.  The decreases in operating margin on these gathering systems were attributable to the aforementioned production declines from gas wells connected to these systems. 

                General and Administrative Costs

General and administrative expenses were $376,916 for the three months ended June 30, 2011, which represented an increase of $31,614 from the $345,302 in such expenses we recognized for the three months ended June 30, 2010.  The primary driver of this increase was a net increase of $66,000 in stock-based compensation expense between the two periods.  This increase was primarily due to a credit of $49,676 in 2010 related to non-vested options forfeited by former management.  

General and administrative expenses were $742,658 for the six months ended June 30, 2011, which represented a decrease of $65,097 from the $807,755 in such expenses we recognized for the six months ended June 30, 2010.  This decrease was primarily attributable to lower personnel costs, board fees and professional fees, partially offset by a $55,000 increase in stock compensation due to the aforementioned credit in 2010. We expect general and administrative expenses to remain lower in 2011, relative to the comparable 2010 periods, as we continue to manage our overall level of fixed costs.

We incurred acquisition and financing related costs of $47,867 during the three and six months ended June 30, 2011, primarily related to the pending acquisition of a pipeline located in Delmar, New York from American Midstream.

Acquisition costs in 2010, all of which were recognized in the first quarter 2010, were related to our Hickory Creek acquisition in January 2010.  See Note 3 in the accompanying notes to our consolidated financial statements.

                Consent Solicitation Costs

Consent solicitation costs of $1,444,092 and $1,542,963 for the three and six months ended June 30, 2010, respectively, were for legal and proxy preparation costs we incurred related to the consent solicitation initiated by our current CEO in 2010.

                Other Income (Expense)

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

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

                Liquidity and Capital Resources

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

We had available cash of $555,565 at June 30, 2011.

Net cash provided by operating activities totaled $434,270 for the six months ended June 30, 2011, resulting primarily from our net loss, after adding back our non-cash charges, including depreciation, depletion and amortization and stock based compensation and deducting its non-cash tax benefit, and the receipt of a $250,000 returned deposit.  We used $846,238 of cash in operations during the six months ended June 30, 2010, resulting primarily from our net loss, partially offset by non-cash charges and changes in working capital during the year.

We used $58,176 of cash in investing activities during the six months ended June 30, 2011, primarily to install a cathodic protection system at our Waxahachie system, which will lengthen the expected life of the system.  During the six months ended June 30, 2010 , we used $3.7 million of cash in investing activities, primarily for the purchase of our Hickory Creek Gathering System.

 During 2010, the Company executed premium finance agreements for its insurance premiums.  The total original principal amount of the notes 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 period changes.  The Company expects it will be able to finance the renewal of the policy premiums related to these coverages at the date of policy renewals.         

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

We expect to close the aforementioned acquisition from American Midstream during September 2011.  The combined purchase price and associated due diligence and legal costs to be incurred from July 1, 2011 until closing are expected to total approximately $75,000.  We expect to finance the acquisition from cash on hand.

                Off-Balance Sheet Arrangements

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

                Non-GAAP Financial Measure

We evaluate our operations using operating margin, which we define as revenues less cost of purchased gas, operating and maintenance expenses and reimbursable costs.  Such amounts are before 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.