Filed Pursuant to Rule 424(b)(3)
                                                             File No. 333-125564

PROSPECTUS SUPPLEMENT NO. 1
(To Prospectus Dated March 22, 2006)

                            NATURAL GAS SYSTEMS, INC.

                                  Common Stock

         This document supplements our prospectus dated March 22, 2006 and
should be read in conjunction with the prospectus. This prospectus supplement
describes certain recent developments and contains information regarding recent
results of operations concerning Natural Gas Systems, Inc., and must be
delivered with the prospectus.

Transaction Involving our Delhi Field

         As previously reported in a Current Report on Form 8-K that we filed
with the SEC on May 11, 2006, our wholly-owned subsidiary, NGS Sub Corp, entered
into a purchase and sale agreement with Denbury Onshore, LLC, a subsidiary of
Denbury Resources, Inc. (NYSE symbol: DNR) on May 8, 2006 to conduct an enhanced
oil recovery project utilizing CO2 flood technology in our Delhi Holt Bryant
Unit within the Delhi Field in northeast Louisiana (the "Delhi Unit"). On June
12, 2006, this transaction closed and we received approximately $50 million from
Denbury and delivered to Denbury an initial 100% working interest and 80% net
revenue interest in the Delhi Unit, and a 75% working interest and an 80% net
revenue interest (proportionately reduced to 60%) in certain other depths of the
Delhi Field. We retained a separate 4.8% royalty interest in the Delhi Field
(including the Delhi Unit) and a 25% working interest in certain other depths of
the Delhi Field (excluding the Delhi Unit, except as described below). Under the
terms of the agreement, Denbury has agreed to contribute all development
capital, technical expertise and required amounts of proven reserves of carbon
dioxide that will be injected into the Delhi Unit oil reservoirs. After the
project generates $200 million of net cash flows before capital expenditures for
Denbury, we will regain a 25% working interest (20% net revenue interest) in the
Delhi Unit.

         As a result of this transaction, our liquidity has significantly
improved and our forward looking results from operations will likely change as
more fully described under "Significant Improvement in Liquidity" and "Forward
Looking Results Will Likely Change", respectively, in "Management's Discussion
and Analysis of Financial Condition and Results of Operations," below.

         Copies of the Purchase and Sale Agreement and other definitive
agreements relating to this transaction have been filed with the SEC as exhibits
to our Current Report on Form 8-K filed with the SEC on June 15, 2006. For
information on obtaining our Form 8-K, including exhibits, see the discussion in
the prospectus under the caption "Where You Can Find More Information."

             The date of this Prospectus Supplement is June 28, 2006

                                       1

Management's Discussion and Analysis of Financial Condition and Results of Operations The following information updates the discussion under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operations" in the prospectus and should be read in conjunction with that discussion. Liquidity and Capital Resources Significant Improvement in Liquidity As a result of our recent transaction with Denbury Resources, Inc. (NYSE symbol: DNR) described above, our liquidity has improved significantly. Under the terms of this transaction, on June 12, 2006 we received approximately $50 million in cash, and a 25% after payout back-in working interest in the enhanced oil recovery project Denbury has undertaken to fund and operate. Of the approximately $50 million in proceeds, we immediately used approximately $5.4 million to repay in full our credit facility and used approximately $257,000 to repay a subordinated loan to our Chairman (see "Repayment of Loans" below). Consequently, we currently have no indebtedness, other than ordinary course trade payables, and we have sufficient cash resources to continue with the implementation of our business strategy for the foreseeable future. We plan to deposit a minimum of $3 million, and a maximum of up to $16 million of the proceeds, with the U. S. Treasury and the Louisiana Department of Revenue for income taxes due on the gain on sale of our Delhi property, depending on the amount of IRC 1031 like-kind property exchanges we ultimately consummate. The estimated remaining balance of these proceeds (being a range of approximately $28.3 million to $41.3 million, depending on our ultimate taxable gain) will be used to identify and close additional oil and gas investment opportunities that fit our business plan, and for working capital and general corporate purposes. We have not determined the exact amounts we plan to expend on the above uses or the timing of such expenditures. The amounts actually expended and the timing are at our discretion and may vary significantly depending upon a number of factors, including our ability to identify and close additional oil and gas opportunities that fit our business plan within the 45 and 180 day windows allotted to identify and consummate any IRC 1031 like-kind exchanges. Pending their use as set forth above, such proceeds will be invested in a U.S. Government money market account. Repayment of Loans As previously reported in a Current Report on Form 8-K filed by us on February 2, 2005 with the SEC, we entered into a senior secured loan agreement (the "Loan Agreement") with Prospect Energy Corporation ("Prospect") providing for borrowings by us of up to $4.8 million. The borrowings were secured by substantially all of our assets. The outstanding indebtedness bore interest at an annual rate equal to the greater of (a) 14% and (b) the Treasury Rate plus 9%, with interest payable in arrears on the last day of each month. All outstanding indebtedness was to become due in full on February 2, 2010. Pursuant to a number of amendments to the Loan Agreement, the total face amount of borrowings at maturity drawn by us was $5.0 million. On May 31, 2006, we voluntarily prepaid all amounts due under the Loan Agreement totaling $5,437,352, representing the then-outstanding principal balance of $5,000,000, all accrued and unpaid interest, a prepayment penalty and certain other amounts due and owing under the Loan Agreement. We also issued Prospect an additional five-year warrant to purchase up to 100,000 shares of our common stock at an exercise price of $2.71 per share in satisfaction of a disputed obligation relating to a voluntary waiver by Prospect of a technical breach of a negative covenant by us. Concurrent with this repayment the Loan Agreement was terminated and all of the collateral attached thereto was released. 2

On March 3, 2006, we borrowed $250,000 from Laird Q. Cagan, the chairman of our board, for working capital. This loan had a one-year term and accrued interest at the annual rate of 10%, payable at maturity. The loan also had certain acceleration provisions in the event we were to raise additional capital in excess of $2 million. On June 13, 2006, we voluntarily prepaid all amounts due under this loan totaling $257,058, representing the then-outstanding principal balance and all accrued and unpaid interest. Mr. Cagan acts as our non-exclusive placement agent for capital raising services through Chadbourn Securities, Inc., and his company, Cagan McAfee Capital Partners, provides financial advisory services to us under the terms of a written agreement previously filed with the SEC. Cash Flow for the nine months ended March 31, 2006 Cash used in operating activities for the nine months ended March 31, 2006 was $632,967 and cash used in operations for the comparative period was $739,684. The decrease in cash used in operating activities was primarily due to lower net cash losses from operations before changes in working capital, offset with higher operating expenses resulting in higher operating losses. Cash used in investing activities in the nine months ended March 31, 2006 and 2005 was $2,891,009 and $2,186,724, respectively. In 2006, the majority of the development capital expenditures were spent on the 2005 Delhi Development Drilling Program and for the purchase of an additional net revenue interest in one of our existing field. For the nine months ended March 31, 2005, we expended approximately $1,836,878, in capital expenditures, of which approximately $725,000 was for the acquisition of producing properties in Tullos Field Area. Cash provided by financing activities for the nine months ended March 31, 2006 was $1,183,119. This was primarily from loan proceeds of $1,250,000, offset by $6,754 used to pay off the remaining note for property insurance; $22,654 for deferred financing fees related to the additional $1.0 million drawdown from Prospect, and $37,473 for miscellaneous transaction costs related to equity raising activities. Comparatively, $3,536,987 was provided in the comparable period which consisted of $3,855,721 in net proceeds from loans, $1,737,336 payments on notes, $1,678,307 of gross cash proceeds from the private sale of our common stock and $259,705 of deferred financing fees. Budgeted Capital Expenditures. Our 2005 Delhi Development Drilling Program began in early October, 2005 and completion activities ended in March 2006. As of March 31, 2006 we had drilled and completed five wells at an estimated total cost to date of $1.7 million. The two option wells we originally planned for the 2005 program (wells six and seven) were postponed due to heavy rains at Delhi during January 2006. Results of Operations Forward-Looking Results Will Likely Change Due to our purchase and sale agreement with Denbury Onshore LLC, described under "Transaction Involving our Delhi Field" above, further initiatives concerning our Delhi Development Drilling Program are expected to be replaced with the much larger enhanced oil recovery (EOR) project utilizing CO2 flood technology, which Denbury has undertaken to fund and operate. The Denbury agreement, although exceeding our original expectations for development results at Delhi, will result in the immediate loss of production and revenues from Delhi (excluding our override on existing production) until such time as the EOR project is completed and brought online by Denbury. Without further acquisitions of new properties, or production increases at our Tullos Field Area, our production and revenues will decline in the foreseeable future, as compared to our March 31, 2006 results. 3

Summary for three and nine month periods ended March 31, 2006 We have continued our growth in critical metrics of production and revenues while limiting our cash overhead costs. In the most recent three months ended March 31, 2006, our sales volumes and revenues increased by 74% and 132%, respectively, over the prior year three month period. For the nine months ended March 31, 2006, our sales volumes and revenues increased by 85% and 131%, respectively, over the prior year nine month period. After accounting for lease operating expense and production taxes, field income before depletion expense increased 134% and 115% for the three and nine months ended March 31, 2006, respectively, while general and administrative expenses declined 31% and rose 8%, respectively for the same periods. Losses from Operations declined 49% and 9% for the comparable three and nine month periods. The drilling results of our 2005 Delhi Development Drilling Program did not produce the immediate favorable results we expected. From a technical perspective, we generally found the targeted reservoirs "up-dip" of previously watered-out zones at the structural level and thickness predicted. It appears that the reservoirs we targeted became less permeable toward the truncation point, or updip limit, thereby resulting in far less production than anticipated. We believe that artificial stimulation of the reservoirs, or hydraulic fracturing, may result in improved production rates. Such stimulations would require further expenditures and contain an element of risk as to success. Furthermore, the problems encountered in drilling and completing the wells due to the changed reservoir quality and quality of the vendor services we received led to far higher capital expenditures than budgeted. Three months ended March 31, 2006 compared to three months ended March 31, 2005. The following table sets forth certain financial information with respect to our oil and gas operations. Three Months Ended March 31, ------------------------ Net to NGS 2006 2005 Variance % change ----------- ----------- ------------ ----------- Sales Volumes: Oil (Bbl) 14,496 6,545 7,951 121% Gas (Mcf) 10,003 16,378 (6,375) -39% Oil and Gas (Boe) 16,163 9,275 6,888 74% Revenue data (a): Oil Revenue $ 794,872 $ 267,225 $ 527,647 197% Gas Revenue 83,730 111,722 (27,992) -25% ----------- ----------- ------------ Total oil and gas revenues $ 878,602 $ 378,947 $ 499,655 132% Average prices (a): Oil (per Bbl) $ 54.83 $ 40.83 $ 14.00 34% Gas (per Mcf) 8.37 6.82 1.55 23% Oil and Gas (per Boe) 54.36 40.86 13.50 33% Expenses (per BOE) Lease operating expenses and production taxes $ 33.84 $ 25.93 $ 7.91 31% Depletion expense on oil and gas properties 8.12 6.01 2.11 35% (a) Includes the cash settlement of hedging contracts Net Loss. For the three months ended March 31, 2006, we reported a net loss of $608,132 or $0.02 loss per share on total revenues of $878,602, as compared to a net loss of $906,936 or $0.04 loss per share on total revenues of $378,947 for the three months ended March 31, 2005. The decrease in loss is attributable primarily to higher revenues due to increased production and sales volumes, higher commodity prices, lower general and administrative expenses, offset by unfavorable nonrecurring lease operating costs. 4

Sales Volumes. Oil sales volumes, net to our interest, for the three months ended March 31, 2006 increased 121% to 14,496 Bbls, compared to 6,545 Bbls for the three months ended March 31, 2005. The increase in sales volumes is primarily due to oil sales from the Chadco acquisition in the Tullos Field Area and the result of workovers, recompletions and the development drilling program at Delhi field. Net natural gas volumes sold for the three months ended March 31, 2006 were 10,003 Mcfs, a decrease of 39% from the three months ended March 31, 2005. The normal decline rate is primarily attributable for this decrease, slightly offset by the new Delhi 92-2 well which was drilled and completed in early November. Production. Oil production varies from oil sales volumes by changes in crude oil inventories, which are not carried on the balance sheet. Net oil production for the three months ended March 31, 2006 increased 97% to 13,890 Bbls, compared to 7,046 Bbls for the three months ended March 31, 2005. This is primarily due to the acquisition of additional wells in the Tullos Field Area and results of development drilling and other work in the Delhi Field. Net natural gas production for the three months ended March 31, 2006 decreased 54% to 10,147 Mcfs, compared to 21,846 Mcfs for the three months ended March 31, 2005, due to depletion in all gas wells at Delhi field. Oil and Gas Revenues. Revenues presented in the table above and discussed herein represent revenue from sales of our oil and natural gas production volumes, net to our interest. Production sold under fixed price delivery contracts, which have been designated for the normal purchase and sale exemption under SFAS 133, are also included in these amounts. Realized prices may differ from market prices in effect during the periods, depending on when the fixed delivery contract was executed. Oil and gas revenues increased 132% for the three month period ended March 31, 2006, compared to the same period in 2005, as a result of increases in sales volumes due primarily to the Chadco acquisition of producing leases in the Tullos Field Area and the Delhi Development drilling program. Another component of the revenue increase is a 33% increase in the sales prices received per BOE during the three months ended March 31, 2006 as compared to the three months ended March 31, 2005. Lease Operating Expenses. Lease operating expenses for the three months ended March 31, 2006 increased $306,551 from the comparable 2005 period to $547,029. The increase in operating expenses in 2006 is primarily attributable to (1) an increase in the number of active wells due to the acquisition of producing properties in the Tullos Field Area; (2) substantial increases in overall industry service costs and (3) nonrecurring lease cleanup costs. General and Administrative Expenses. General and administrative expenses were $593,271for the three months ended March 31, 2006, a decrease of $262,669 from $855,940 for the three months ended March 31, 2005. Non-cash stock compensation expense decreased approximately $400,000 from the prior comparative quarter, offset by higher overall general and administrative expenses in the current quarter due to significant expenses associated with a being a public registrant, including expenses for audited financial statements, SEC counsel, outside engineering estimates, D&O insurance, outside director fees and other related costs. Depletion and Amortization Expense. Depletion and amortization expense increased $75,516 for the three months ended March 31, 2006 to $131,246 from $55,730 for the same period in 2005. The increase is primarily due to a 74% increase in sales volumes and a 35% increase in the average depletion rate, period over period. 5

Interest Expense. Interest expense for the three months ended March 31, 2006 increased $86,364 to $221,694 (of which $160,713 was cash expense) compared to $135,330 (of which $70,762 was cash expense) for the three months ended March 31, 2005. The increase in interest expense was primarily due to interest expense associated with the Prospect facility, which was only partially outstanding in the comparable period. Nine months ended March 31, 2006 compared to nine months ended March 31, 2005 Nine Months Ended March 31, ------------------------------ Net to NGS 2006 2005 Variance % change -------------- -------------- -------------- -------------- Sales Volumes: Oil (Bbl) 35,277 15,747 19,530 124% Gas (Mcf) 43,962 43,495 467 1% Oil and Gas (Boe) 42,604 22,996 19,608 85% Revenue data (a): Oil Revenue $ 1,831,804 682,679 $ 1,149,125 168% Gas Revenue 420,618 293,203 127,415 43% -------------- -------------- -------------- Total oil and gas revenues $ 2,252,422 $ 975,882 $ 1,276,540 131% Average prices (a): Oil (per Bbl) $ 51.93 $ 43.35 $ 8.58 20% Gas (per Mcf) 9.57 6.74 2.83 42% Oil and Gas (per Boe) 52.87 42.44 10.43 25% Expenses (per BOE) Lease operating expenses and production taxes $ 33.94 $ 26.10 $ 7.84 30% Depletion expense on oil and gas properties 7.52 6.82 0.70 10% (a) Includes the cash settlement of hedging contracts Net Loss. For the nine months ended March 31, 2006, we reported a net loss of $1,950,074 or $0.08 loss per share on total revenues of $2,252,422, as compared with a net loss of $1,682,775 or $0.07 loss per share on total revenues of $975,882 for the nine months ended March 31, 2005. The increase in loss is attributable to overall increases in lease operating and general and administrative expenses including nonrecurring lease operating costs, partially offset by increases in revenues due to higher sales volumes and sales prices. Excluding non-cash stock compensation expense of $381,385, our net loss for the nine months ended March 31, 2006 was $1,568,689, or $0.06 loss per share. By comparison, excluding non-cash stock compensation expense of $620,588 for the nine months ended March 31, 2005, our net loss was $1,062,187, or $0.05 loss per share. Sales Volumes. Oil sales volumes, net to our interest, for the nine months ended March 31, 2006 increased 124% to 35,277 Bbls, compared to 15,747 Bbls for the nine months ended March 31, 2005. The increase in sales volumes is primarily due to oil sales from the Chadco acquisition in the Tullos Field Area, the result of workovers and recompletions in our portfolio and the results of the development drilling program at Delhi field. Net natural gas volumes sold for the nine months ended March 31, 2006 were 43,962 Mcfs, an increase of 1% from the nine months ended March 31, 2005. Normal production declines were offset with new sales volumes from the Delhi 92-2 well which was drilled and completed in late 2005. 6

Production. Oil production varies from oil sales volumes by changes in crude oil inventories, which are not carried on the balance sheet. Net oil production for the nine months ended March 31, 2006 increased 122% to 36,390 Bbls, compared to 16,421Bbls for the nine months ended March 31, 2005. This is primarily due to the acquisition of wells in the Tullos Field Area, the result of workovers and recompletions in our portfolio and the results of the development drilling program at Delhi field. Our net oil stock ending inventory decreased approximately 28% at March 31, 2006 to approximately 4,300 Bbls, as compared to approximately 6,000 Bbls at March 31, 2005. Decreases in oil inventory were attributable to coordinating with our purchaser to pick up half loads at Tullos Field area since many of these leases do not make a full truckload within one month (one truckload equals ~ 160 Bbls). This has caused erratic oil runs from month to month. Net natural gas production for the nine months ended March 31, 2006 decreased 10% to 53,716 Mcfs, compared to 59,367 Mcfs for the nine months ended March 31, 2005. Normal production declines were offset with new production from the Delhi 92-2 well which was drilled and completed in late 2005. Oil and Gas Revenues. Revenues presented in the table above and discussed herein represent revenue from sales of our oil and natural gas production volumes, net to our interest. Production sold under fixed price delivery contracts, which have been designated for the normal purchase and sale exemption under SFAS 133, are also included in these amounts. Realized prices may differ from market prices in effect during the periods, depending on when the fixed delivery contract was executed. Oil and gas revenues increased 131% for the nine month period ended March 31, 2006, compared to the same period in 2005, as a result of a 85% increase in production volumes due to the Chadco and Atkins acquisitions of producing leases in the Tullos Field Area and increases in production from our Delhi Field as a result of the development drilling program. Another component of the increase was a 25% increase in the average sales prices we received per BOE during the nine months ended March 31, 2006 as compared to the nine months ended March 31, 2005. Lease Operating Expenses. Lease operating expenses for the nine months ended March 31, 2006 increased $845,732 from the comparable 2005 period to $1,445,923. The increase in operating expenses for this nine period is primarily attributable to (1) an increase in the number of active wells due to the acquisition of properties in the Tullos Field Area, (2) substantial increases in overall industry service costs, (3) high workover costs associated with our Delhi 87-2 and 197-2 wells, repairs to our salt water disposal system and repairs to two separate gas gathering line leaks, and (4) nonrecurring lease cleanup costs. On a BOE basis, lease operating expense and production taxes totaling $33.94 per BOE did not meet our expectations for the nine months ended March 31, 2006, as compared to the prior year's comparable period of $26.10. The unfavorable variance in the current period was predominately due to the previously mentioned workover costs associated with an unusually large number of our Delhi wells, combined with the loss of production from well downtime while working over the wells. Over half of this unfavorable variance was attributable to workover expenses incurred to maintain production on our Delhi 87-2 well, which currently accounts for the majority of our production from our Delhi Field. As previously reported, our Delhi 87-2 well is over 50 years old. General and Administrative Expenses. General and administrative expenses for the nine months ended March 31, 2006 were $1,839,655, an increase of $132,784 as compared to $1,706,871 for the comparable prior year period. The increase is primarily due to an increase in employees from two to five and implementation of an outsourced property accounting service with Petroleum Financial Incorporated. Overall general and administrative expenses are high due to expenses associated with a being a public registrant, including expenses for audited financial statements, SEC counsel, outside engineering estimates, director & officer insurance, outside director fees and other related costs; offset by a decrease in non-cash stock compensation expense of approximately $239,000, from the comparative period. 7

Depletion and Amortization Expense. Depletion and amortization expense increased $163,773 for the nine months ended March 31, 2006 to $320,594 from $156,821 for the same period in 2005. The increase is primarily due to an 85% increase in sales volumes and a 10% increase in the average depletion rate, period over period. Interest Expense. Interest expense for the nine months ended March 31, 2006 increased $432,690 to $634,388 (of which $443,229 was cash expense) compared to $201,698 (of which $168,475 was cash expense) for the nine months ended March 31, 2005. The increase in interest expense was primarily due to interest expense associated with the Prospect facility, which was only partially outstanding in the comparable period. Approval to List our Shares on the American Stock Exchange On June 20, 2006, we received approval from the American Stock Exchange to accept our shares for trading. However, AMEX approval is contingent upon our being in compliance with all applicable listing standards on the date we begin trading on the Exchange, and may be rescinded if we are not in compliance with such standards. Although we can give no assurances, we are actively attempting to complete this process, with the expectation that our shares may begin trading by early July, 2006. 8