Edgar Filing: NATURAL GAS SYSTEMS INC/NEW

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-KSB

ý	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES ACT OF 1934
For The Fiscal Year Ended June 30, 2004
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF SECURITIES EXCHANGE ACT OF 1934
For the transition period to

Commission File Number

NATURAL GAS SYSTEMS, INC.
(Exact name of registrant as specified in charter)

Nevada (State of incorporation)		41-1781991 (I.R.S. employer identification number)
820 Gessner, Suite 1340, Houston, Texas 77024 (Address of principal executive offices and zip code)
Registrant's telephone number, including area code: (713) 935-0122

Securities registered pursuant to Section 12(b) of the Exchange Act:

Securities registered pursuant to Section 12(g) of the Exchange Act:
Common Stock, $.001 Par Value

(Title of class and shares outstanding)

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-B 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-KSB or any amendment to this Form 10-KSB.

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes: ý No o

Issuer's revenues for its most recent fiscal year: $118,158

As of August 31, 2004, the aggregate market value of common stock held by non-affiliates of the registrant was approximately $19,530,703, assuming solely for purposes of this calculation that all directors and executive officers of the registrant and all stockholders beneficially owning more than 10% of the registrant's common stock are "affiliates." This determination of affiliate status is not necessarily a conclusive determination for other purposes.

The number of shares of common stock outstanding on August 31, 2004 was 23,145,406 shares.

DOCUMENTS INCORPORATED BY REFERENCE into Part III hereof Portions of the Proxy Statement to be filed with the Commission in connection with the Company's 2004 Annual Meeting.

Transitional Small Business Format (Check One): Yes o No ý

Glossary of Selected Petroleum Terms

The following abbreviations and definitions are terms commonly used in the oil and natural gas industry and throughout this report on Form 10-KSB:

"BBL" A standard measure of volume for crude oil and liquid petroleum products. One barrel equals 42 U.S. gallons.

"BCF" Billion cubic feet of natural gas.

"BOE" Barrels of oil equivalent. Calculated by converting 6 MCF of natural gas to 1 BBL of oil.

"BTU" or "British Thermal Unit" The standard unit of measure of energy equal to the amount of heat required to raise the temperature of one pound of water 1 degree Fahrenheit. One BBL of crude is typically 5.8 MMBTU, and one standard MCF is typically 1 MMBTU.

"Field" An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geologic structural feature and/or stratigraphic feature.

"gross well" The total number of wells participated in, regardless of the amount of working interest owned. (See net wells).

"MBOE" One thousand barrels of oil equivalent.

"MCF" One thousand cubic feet of natural gas at standard conditions, being approximately sea level pressure and 60 degrees Fahrenheit temperature. Standard pressure in the state of Louisiana is deemed to be 15.025 psi by regulation but varies in other states.

"MMBTU" One million British thermal units (BTU's).

"MMCF" One million cubic feet of natural gas.

"net wells" The aggregate fractional working interests owned, e.g., a 20% working interest in each of 5 gross wells equals one net well. (See Gross Well).

"NGL" Natural gas liquids, being the combination of ethane, propane, butane and natural gasolines that can be removed from natural gas through processing, typically through refrigeration plants that utilize low temperatures, or through J-T plants that utilize compression, temperature reduction and expansion to a lower pressure.

"NYMEX" New York Mercantile Exchange.

"permeability" The measure of ease with which petroleum can move through a reservoir.

"porosity" (of sand or sandstone) The relative volume of the pore space compared to the total bulk volume of the reservoir.

"royalty or royalty interest" The mineral owner's share of oil or gas production (typically ¹/8, ¹/6 or ¹/4), free of costs, but subject to severance taxes unless the lessor is a government. In certain circumstances, the royalty owner bears a proportionate share of the costs of making the natural gas saleable, such as processing, compression and gathering.

"psi" pounds per square inch, a measure of pressure.

"shut-in well" A well that is not on production, but has not been plugged and abandoned. Wells may be shut-in in anticipation of future utility as a producing well, plugging and abandonment or other use.

"Standardized measure" The standardized measure is an estimate of future net reserves from a property, and is calculated in the same exact same fashion as a PV-10 value, except that the projected

revenue stream is adjusted to account for the estimated amount of federal income tax that must be paid.

"working interest" The interest in the oil and gas in place which is burdened with the cost of development and operation of the property. Also called the operating interest.

"work-over" A remedial operation on a completed well to restore, maintain or improve the well's production.

PART I.

ITEM 1. BUSINESS

General

Natural Gas Systems, Inc. ("NGS", the "Company", "we", "us" or "our") is a development stage company formed to acquire established crude oil and natural gas properties and exploit them through the application of conventional and specialized technology, with the objective of increasing production, ultimate recoveries, or both. At June 30, 2004, NGS conducted operations through its 100% working interest in the Delhi Field. The Company currently operates its properties in the State of Louisiana, with three full time employees and a small number of independent contractors and service providers administered from its Houston office.

NGS is a Nevada corporation with its corporate headquarters in Houston, Texas. Its telephone number is 713-935-0122.

Corporate History

Reality Interactive, Inc. ("Reality"), a Nevada corporation, was incorporated on May 24, 1994 for the purpose of developing technology-based knowledge solutions for the industrial marketplace. On April 30, 1999, this company ceased business operations, sold substantially all of its assets and terminated all of its employees. Subsequent to ceasing operations, Reality explored potential business opportunities to acquire or merge with an entity with existing operations, while continuing to file reports with the SEC.

On May 26, 2004, Natural Gas Systems, Inc., a privately owned Delaware corporation formed in September 2003 ("Old NGS"), was merged into a wholly owned subsidiary of Reality. Reality was thereafter renamed Natural Gas Systems, Inc. and adopted a June 30 fiscal year end. As part of the merger, the officers and directors of Reality resigned and the officers and directors of Old NGS became the officers and directors of the Company. Immediately prior to the merger, Reality did not conduct any operations and had minimal assets and liabilities.

The stock of NGS is quoted on the OTC Bulletin Board under the new symbol of NGSY.OB.

All regulatory filings and other historical information including stock prices prior to June 30, 2004 that applied to Reality continue to apply to the Company after the merger.

Business Activities

NGS is a development stage company that seeks to acquire majority working interests of oil and gas resources in established fields and redevelop those fields through the application of capital and technology to convert the oil and gas resources into producing reserves. We focus on established fields with long-lived production from shallow reservoirs, particularly those reservoirs with low permeability. We believe this provides us with the following advantages:

•: By limiting our focus to established fields, we believe we are likely to incur less exposure to the risk of whether resources are present. We also reduce the amount of capital expenditures necessary for infrastructure, such as roads, water handling facilities and pipelines.
•: We prefer to acquire long-lived properties in order to reduce risk from short-term oil and gas price volatility.
•: We focus on shallow reservoirs in order to reduce technical and operational risks associated with higher pressures, temperatures and their attenuate costs on deeper wells.

•: We seek to own majority working interests in order to maintain full control of operations and development.
•: We are particularly interested in applying lateral drilling technology, especially to opportunities with low permeability, thin bed reservoirs.

Old NGS purchased its first property in September 2003 through the acquisition of a 100% working interest in the Delhi Unit in northeastern Louisiana (see Properties section below). The purchase included six producing wells, one salt water disposal well and 37 shut-in wells with aggregate average production of approximately 18 barrels of oil per day ("BOPD") and no gas sales. The Delhi Unit encompasses approximately 13,636 acres. We own rights to the top of the Massive Anhydride Formation, less and except the Mengel Reservoir, which is being produced by another operator in a small number of wells.

In late 2003, we executed an agreement with Verdisys, Inc., the holder of the U.S. license rights to a patented lateral drilling technology. Under the license agreement, Verdisys has agreed to provide us with lateral drilling services based on our projected needs, subject only to adequate advance notice, at a fixed price not to exceed the lowest price offered to any other customer for similar services. Although we may find the Verdisys technology useful, our business plan does not rely on it. To date, we have used the Verdisys technology in only two wells, the results of which were inconclusive.

Markets and Customers

Marketing of oil and natural gas production is influenced by many factors that are beyond our control, the exact effect of which is difficult to predict. These factors include changes in supply and demand, market prices, government regulation and actions of major foreign producers.

Over the past 20 years, crude oil price fluctuations have been extremely volatile, with oil prices varying from $8.50, to in excess of $40 per barrel. Worldwide factors such as geopolitical, macroeconomic, supply and demand, refining capacity, petrochemical production and derivatives trading, among others, influence prices for crude oil. Localized influences include regulation and transportation issues unique to certain producing regions.

In the domestic U.S. market where we operate, crude oil and condensate production are readily transportable and marketable. We sell all of our oil production from the Delhi Field to Genesis Petroleum, LLC, a crude oil purchaser, at competitive spot field prices. We believe that other crude purchasers are readily available.

Similarly over the last 20 years, domestic natural gas prices have been volatile, ranging from $1 to $9 per MCF. The spot market for natural gas, changes in supply and demand, derivatives trading, pipeline availability, BTU content of the gas and weather patterns, among others, cause natural gas prices to be subject to significant fluctuations. Due to the practical difficulties in transporting natural gas, price influences tend to be more localized for natural gas than for crude oil.

All of our current natural gas production is located in northeastern Louisiana. There is only one gas pipeline sales point readily available, which reduces our leverage in negotiating a more favorable transportation charge and sales price. The current gas sales line is also a delivery line to customers, downstream of the pipeline's processing and treating facilities, thus making the pipeline very sensitive to the quality of gas sold into our point of interconnection.

We presently sell all of our gas under a short-term contract with a gas marketer. We believe that other gas marketers are readily available. The sales price is typically based on either a daily price average or a monthly "spot" (Index) price for the applicable production region. Title to the gas passes to the purchaser at the metered interconnection to the transportation pipeline, where the Index price is reduced by certain pipeline charges. Gas sold from the Delhi Field incurs a $0.25 per MMBTU

deduction from the Henry Hub price, the primary pricing market for natural gas futures, less an additional $0.085 per MCF charge for transportation. These costs, along with the costs for gas processing and transportation prior to delivery to the sales point, are deducted from the gas sales receipts before calculation and distribution of royalties.

Competition and Regulation

The oil and gas industry is highly competitive. As a small independent, we must compete against companies with substantially larger financial and other resources in all aspects of their businesses.

Oil and gas drilling and production operations are regulated by various Federal, state and local agencies. These agencies issue binding rules and regulations that carry penalties, often substantial, for failure to comply. We anticipate the aggregate burden of Federal, state and local regulation will continue to increase, including in the area of rapidly changing environmental laws and regulations. We also believe that our present operations substantially comply with applicable regulations. To date, such regulations have not had a material effect on our operations, or the costs thereof. There are no known environmental or other regulatory matters related to our operations that are reasonably expected to result in material liability to us that have not been recognized in our financial statements or their footnotes. We do not believe that capital expenditures related to environmental control facilities or other regulatory matters will be material in the near term. NGS cannot predict what subsequent legislation or regulations may be enacted or what affect it will have on our operations or business.

RISK FACTORS

Risks related to the Company

Need for additional financing.

We currently do not have sufficient capital reserves to satisfy our obligations and continue operations through the end of 2004, and therefore have an immediate need for capital. While we are exploring various capital raising avenues, there can be no assurance that we will be able to obtain the sufficient short-term capital needed to sustain operations. Further, we are incurring losses from operating activities. Our current capital reserves will not be sufficient to allow us to fully execute our business plan within the time frame projected and take advantage of available business opportunities during fiscal year 2005. The full and timely development and implementation of our business plan and growth strategy will require significant additional resources. We may not be able to obtain the working capital necessary to implement our growth strategy. Furthermore, our growth strategy may not produce material revenue even if successfully funded. Management intends to explore a number of options to secure alternative sources of capital, including the issuance of secured debt, volumetric production payments, subordinated debt, or additional equity, including preferred equity securities or other equity securities. We might not succeed, however, in raising additional equity capital or in negotiating and obtaining additional and acceptable financing when we need it. Our ability to obtain additional capital will also depend on market conditions, national and global economies and other factors beyond our control. Even if we are able to obtain the short-term capital necessary to sustain our operations, if adequate capital is not available or is not available on acceptable terms at a time when we needed it, our ability to close acquisitions, execute our growth plans, develop or enhance our services or respond to competitive pressures will be significantly impaired. There are no assurances that we will be able to implement or capitalize on various financing alternatives or otherwise obtain required working capital, the need for which is substantial given our operating loss history. (See Liquidity and Capital Resources, Item 6, for further discussion.)

We have a limited operating history.

We are a development stage company with a limited operating history, and we face all the risks common to companies in their early stages of development, including undercapitalization and uncertainty of funding sources, high initial expenditure levels and uncertain revenue streams, an unproven business model, and difficulties in managing growth. Our prospects must be considered in light of the risks, expenses, delays and difficulties frequently encountered in establishing a new business. Any forward-looking statements in this report do not reflect any adjustments that might result from the outcome of these types of uncertainty. Since inception, we have incurred significant losses. No assurance can be given that we will be successful. While our management has previously carried out or been involved with acquisition and production activities in the oil and gas industry while employed by other companies, there can be no assurance that our intended acquisition targets and development plans will lead to the successful development of oil and gas production revenue.

We may incur unforeseen costs and we may need to raise capital in addition to that required by our business plan.

We are currently operating at a loss and intend to increase our operating expenses significantly as we expand our acquisitions and oil and gas production. Our current cash reserves are only sufficient to fund short-term operations, excluding debt service. Additionally, we may encounter unforeseen costs that could also require us to seek additional capital. We currently do not have any permanent arrangements or credit facilities in place as a source of funds should this need arise, and there can be no assurance that we will be able to raise sufficient additional capital on acceptable terms, if at all. Any additional financing may result in significant dilution to our existing stockholders.

We utilize licensed technology from third parties in certain aspects of our operations.

We utilize a variety of technologies in the oil and gas development and drilling process. We do not have any patents or copyrights for the technology we utilize. Instead, we license or outsource most of the technology integral to our business from third parties. Our commercial success will depend in part on this licensed technology not infringing on the propriety rights of others and not breaching technology licenses that cover the technology we use in our business. It is uncertain whether any third party patents will require us to utilize or develop alternative technology or to alter our business plan, obtain additional licenses, or cease activities that infringe on third-parties' intellectual property rights. Our inability to acquire any third-party licenses, or to integrate the related third-party products into our business plan, could result in delays in development unless and until equivalent products can be identified, licensed, and integrated. Existing or future licenses may not continue to be available to us on commercially reasonable terms. Litigation, which could result in substantial cost to us, may be necessary to enforce any patents licensed to us or to determine the scope and validity of third-party obligations.

Regulatory and accounting requirements may require substantial reductions in proven reserves and limitations of hedging.

We review on a periodic basis the carrying value of our oil and natural gas properties under the applicable rules of the various regulatory agencies, including the SEC. Under these rules, the carrying value of proved oil and natural gas properties may not exceed the present value of estimated future net after-tax cash flows from proved reserves, discounted at 10%. Application of this "ceiling" test generally requires pricing future revenue at the unescalated prices in effect as of the end the fiscal year and requires a write down for accounting purposes

if the ceiling is exceeded, even if prices declined for only a short period of time. We may in the future be required to write down the carrying value of our oil and natural gas properties when oil and natural gas prices are depressed or unusually volatile. Whether we will be required to take such a charge will depend on the prices for oil and natural gas at the end of any fiscal year and the effect of reserve additions or revisions and capital expenditures during such period. If a write down is required, it would result in a charge to earnings but would not impact cash flow from operating activities.

In order to reduce our exposure to short-term fluctuations in the price of oil and natural gas, we may periodically enter into hedging arrangements. Our hedging arrangements would apply to only a portion of our production and provide only partial price protection against declines in oil and natural gas prices. Such hedging arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected, our customers fail to purchase contracted quantities of oil or natural gas or a sudden, unexpected event materially impacts oil or natural gas prices. In addition, our hedging arrangements may limit the benefit to us of increases in the price of oil and natural gas.

Maintaining reserves and revenue in the future depends on successful development and acquisitions.

In general, the volume of production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Except to the extent we acquire properties containing proved reserves or conduct successful development activities, or both, our proved reserves will decline. Our future oil and natural gas production is, therefore, highly dependent upon our level of success in finding or acquiring additional reserves.

We are subject to substantial operating risks.

The oil and natural gas business involves certain operating hazards such as well blowouts, mechanical failures, explosions, uncontrollable flows of oil, natural gas or well fluids, fires, formations with abnormal pressures, hurricanes, pollution, releases of toxic gas and other environmental hazards and risks. We could suffer substantial losses as a result of any of these events. While we carry general liability, control of well, and operator's extra expense coverage typical in our industry, we are not fully insured against all risks incident to our business.

We may not always be the operator of some of our wells. As a result, our operating risks for those wells and our ability to influence the operations for these wells will be less subject to our control. Operators of these wells may act in ways that are not in our best interests.

The loss of key personnel could adversely affect us.

We depend to a large extent on the services of certain key management personnel, including our executive officers, the loss of any of which could have a material adverse effect on our operations. We do not maintain key-man life insurance with respect to any of our employees.

We depend on skilled technical personnel.

We depend to a large extent on the services of skilled technical personnel to operate and maintain our oil and gas fields. Additionally, as our production increases, so does our need for such services. Except for our agreement with Verdisys, we do not have long-term agreements with our drilling and maintenance service providers. Accordingly, there is a risk that any of our service providers could discontinue servicing our oil and gas fields for any reason. Although we believe that we could establish alternative sources for most of our operation and maintenance needs, any delay in locating, establishing relationships, and training our sources

could result in production shortages and maintenance problems, with a resulting loss of revenue to us. We also rely on third-party carriers for the transportation and distribution of our recovered reserves, the loss of any of which could have a material adverse effect on our operations.

Our operations have significant capital requirements.

We have experienced and expect to continue to experience substantial working capital needs due to our active development and acquisition programs. Even if we are able to obtain the short-term capital necessary to maintain our operations, additional financing will be required in the future to fund our growth and operations. No assurances can be given as to the availability or terms of any such additional financing that may be required or that financing will continue to be available under new credit facilities. In the event such capital resources are not available to us, our drilling and other activities would be curtailed.

We may have difficulty managing future growth and the related demands on our resources and may have difficulty in achieving future growth.

We expect to experience rapid growth through acquisitions and development activity for the foreseeable future. Any future growth may place a significant strain on our financial, technical, operational and administrative resources. Our ability to grow will depend upon a number of factors, including our ability to identify and acquire new development or acquisition prospects, our ability to develop existing properties, our ability to continue to retain and attract skilled personnel, the results of our drilling program and acquisition efforts, the success of our technology, hydrocarbon prices and access to capital. There can be no assurance that we will be successful in achieving growth or any other aspect of our business strategy.

We face strong competition from larger oil and natural gas companies.

Our competitors include major integrated oil and natural gas companies and numerous independent oil and natural gas companies, individuals and drilling and income programs. Many of our competitors are large, well-established companies with substantially larger operating staffs and greater capital resources than us. We may not be able to successfully conduct our operations, evaluate and select suitable properties and consummate transactions in this highly competitive environment. Specifically, these larger competitors may be able to pay more for development projects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, such companies may be able to expend greater resources on the existing and changing technologies that we believe are and will be increasingly important to attaining success in the industry.

The oil and natural gas reserve data included in or incorporated by reference in this report are only estimates and may prove to be inaccurate.

There are numerous uncertainties inherent in estimating oil and natural gas reserves and their estimated values. The reserves in this report are only estimates that may prove to be inaccurate because of these uncertainties. Reservoir engineering is a subjective and inexact process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and natural gas reserves depend upon a number of variable factors, such as historical production from the area compared with production from other producing areas and assumptions concerning effects of regulations by governmental agencies, future oil and natural gas prices, future operating costs, severance and excise taxes, development costs and work-over and remedial

costs. Some or all of these assumptions may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected therefrom prepared by different engineers or by the same engineers but at different times may vary substantially. Accordingly, reserve estimates may be subject to downward or upward adjustment. Actual production, revenue and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material. The information regarding discounted future net cash flows included in this report should not be considered as the current market value of the estimated oil and natural gas reserves attributable to our properties. As required by the SEC, the estimated discounted future net cash flows from proved reserves are based on prices and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as the amount and timing of actual production, supply and demand for oil and natural gas, increases or decreases in consumption, and changes in governmental regulations or taxation. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

Any anticipated credit facility may include substantial operating restrictions and financial covenants and we may have difficulty obtaining such credit facility.

We plan to attempt to put in place a credit facility. There can be no assurance that, in the future, commodity prices will not decline, we will not increase our borrowings or the borrowing base will not be adjusted downward. Any anticipated credit facility will likely be secured by a pledge of substantially all of our assets and have covenants that limit additional borrowings, sales of assets and the distributions of cash or properties and that prohibit the payment of dividends and the incurrence of liens. The revolving credit facility also may require that specified financial ratios be maintained. The restrictions of such credit facility and the difficulty in obtaining additional debt financing may have adverse consequences on our operations and financial results, including our ability to obtain financing for working capital, capital expenditures, our drilling program, purchases of new technology or other purposes may be impaired or such financing may be on terms unfavorable to us; we may be required to use a substantial portion of our cash flow to make debt service payments, which will reduce the funds that would otherwise be available for operations and future business opportunities; a substantial decrease in our operating cash flow or an increase in our expenses could make it difficult for us to meet debt service requirements and require us to modify operations; and we may become more vulnerable to downturns in our business or the economy generally.

Our ability to obtain and service indebtedness will depend on our future performance, including our ability to manage cash flow and working capital, which are in turn subject to a variety of factors beyond our control. Our business may not generate cash flow at or above anticipated levels or we may not be able to borrow funds in amounts sufficient to enable us to service indebtedness, make anticipated capital expenditures or finance our drilling program. If we are unable to generate sufficient cash flow from operations or to borrow sufficient funds in the future to service our debt, we may be required to curtail portions of our drilling program, sell assets, reduce capital expenditures, refinance all or a portion of our existing debt or obtain additional financing. We may not be able to refinance our debt or obtain additional financing, particularly in view of current industry conditions, any restrictions on our ability to incur debt under our existing debt or installment purchase arrangements, and the fact that

some or all of our assets are currently pledged to secure obligations under our existing debt or installment purchase arrangements.

Our acquisition program may be unsuccessful, particularly in light of our recent formation and limited history of acquisitions.

Some of our personnel have had significant acquisition experience prior to joining the Company. However, because we have purchased only two properties to date under the Natural Gas Systems name or organization, we may not be in as good a position as our more experienced competitors to execute a successful acquisition program or close additional future transactions.. The successful acquisition of producing properties requires an assessment of recoverable reserves, future oil and natural gas prices, operating costs, potential environmental and other liabilities and other factors. Such assessments, even when performed by experienced personnel, are necessarily inexact and their accuracy inherently uncertain. Our review of subject properties, which generally includes on-site inspections and the review of reports filed with various regulatory entities, will not reveal all existing or potential problems, deficiencies and capabilities. We may not always perform inspections on every well, and may not be able to observe structural and environmental problems even when we undertake an inspection. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of such problems. There can be no assurances that any acquisition of property interests by us will be successful and, if unsuccessful, that such failure will not have an adverse effect on our future results of operations and financial condition.

We cannot market our production without the assistance of third parties.

The marketability of our production depends upon the proximity of our reserves to, and the capacity of, facilities and third party services, including oil and natural gas gathering systems, pipelines, trucking or terminal facilities, and processing facilities. The unavailability or lack of capacity of such services and facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. A shut-in or delay or discontinuance could adversely affect our financial condition. In addition, federal and state regulation of oil and natural gas production and transportation affect our ability to produce and market our oil and natural gas on a profitable basis.

Risks Relating to the Oil and Gas Industry

Oil and Gas Drilling, re-completions and re-working are speculative activities and involve numerous risks and substantial and uncertain costs.

Our growth will be materially dependent upon the success of our future drilling and development program. Drilling for oil and gas and re-working existing wells involve numerous risks, including the risk that no commercially productive oil or natural gas reservoirs will be encountered. The cost of drilling, completing and operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors beyond our control, including unexpected drilling conditions, pressure or irregularities in formations, equipment failures or accidents, adverse weather conditions, compliance with governmental requirements and shortages or delays in the availability of drilling rigs or crews and the delivery of equipment. Although we believe that our focus on re-developing existing oil and gas field and advanced drilling technology should increase the probability of success of our wells and should reduce average finding costs through elimination of prospects that might otherwise be drilled using other traditional methods, drilling or reworking remains a speculative activity. Even when fully utilized, lateral drilling does not predetermine if

hydrocarbons will in fact be present in such structures if they are drilled. Our future drilling activities may not be successful and, if unsuccessful, such failure will have an adverse effect on our future results of operations and financial condition. There can be no assurance that our overall drilling success rate or our drilling success rate for activity within a particular geographic area will not decline. Although we may discuss drilling prospects that we have identified or budgeted for, we may ultimately not lease or drill these prospects within the expected time frame, or at all. We may identify and develop prospects through a number of methods, some of which do not include horizontal drilling. The drilling and results for these prospects may be particularly uncertain. Our drilling schedule may vary from our capital budget. The final determination with respect to the drilling of any scheduled or budgeted wells will be dependent on a number of factors, including, but not limited to: (i) the results of previous development efforts and the acquisition, review and analysis of data; (ii) the availability of sufficient capital resources to us and the other participants for the drilling of the prospects; (iii) the approval of the prospects by other participants after additional data has been compiled; (iv) economic and industry conditions at the time of drilling, including prevailing and anticipated prices for oil and natural gas and the availability of drilling rigs and crews; (v) our financial resources and results; (vi) the availability of leases and permits on reasonable terms for the prospects; and (vii) the success of our drilling technology. There can be no assurance that these projects can be successfully developed or that the wells discussed will, if drilled, encounter reservoirs of commercially productive oil or natural gas. There are numerous uncertainties in estimating quantities of proved reserves, including many factors beyond our control.

Reliance on technological development and possible technological obsolescence.

Our business is dependent upon utilization of changing technology. As a result, our ability to adapt to evolving technologies, obtain new technology and maintain technological advantages will be important to our future success. We believe that our ability to utilize state of the art technologies will give us an advantage over many of our competitors. This advantage, however, is based in part upon technologies developed by others, and we may not be able to maintain this advantage. As new technologies develop, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement such new technologies at substantial cost. There can be no assurance that we will be able to successfully utilize, or expend the financial resources necessary to acquire, new technology, or that others will not either achieve technological expertise comparable to or exceeding that of our Company or that others will not implement new technologies before us. One or more of the technologies we currently utilize by or implement may, in the future, become obsolete. In such case, our business, financial condition and results of operations could be materially adversely affected. If we are unable to utilize the most advanced commercially available technology, our business, financial condition and results of operations could be materially and adversely affected.

Oil and natural gas prices are highly volatile in general and low prices negatively affect our financial results.

Our revenue, profitability, cash flow, future growth and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent upon prevailing prices of oil and natural gas. Lower oil and natural gas prices also may reduce the amount of oil and natural gas that we can produce economically. Historically, the markets for oil and natural gas have been volatile, and such markets are likely to continue to be volatile in the future. Prices for oil and natural gas are subject to wide fluctuation in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control. These factors

include the level of consumer product demand, weather conditions, domestic and foreign governmental regulations, the price and availability of alternative fuels, political conditions, the foreign supply of oil and natural gas, the price of foreign imports and overall economic conditions. It is impossible to predict future oil and natural gas price movements with certainty. Declines in oil and natural gas prices may materially adversely affect our financial condition, liquidity, ability to finance planned capital expenditures and results of operations.

Government regulation and liability for environmental matters may adversely affect our business and results of operations.

Oil and natural gas operations are subject to extensive federal, state and local government regulations, which may be changed from time to time. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity in order to conserve supplies of oil and natural gas. There are federal, state and local laws and regulations primarily relating to protection of human health and the environment applicable to the development, production, handling, storage, transportation and disposal of oil and natural gas, by-products thereof and other substances and materials produced or used in connection with oil and natural gas operations. In addition, we may be liable for environmental damages caused by previous owners of property we purchase or lease. As a result, we may incur substantial liabilities to third parties or governmental entities. We are also subject to changing and extensive tax laws, the effects of which cannot be predicted. The implementation of new, or the modification of existing, laws or regulations could have a material adverse effect on us.

Risks Associated with Our Stock

Our stock price has been and may continue to be very volatile.

Our common stock is thinly traded and the market price has been, and is likely to continue to be, highly volatile. During the 12 months prior to June 30, 2004, our stock price as traded on the OTC Bulletin Board has ranged from $4.75 to $0.60. The variance in our share price makes it extremely difficult to forecast with any certainty the stock price at which you may be able to buy or sell shares of our common stock. The market price for our common stock could be subject to wide fluctuations to factors that our out of our control, such as:

•: Actual or anticipated variations in our results of operations,
•: Naked short selling of our common stock and stock price manipulation
•: Changes or fluctuations in the commodity prices of oil and natural gas
•: General conditions and trends in the oil and gas industry
•: General economic, political and market conditions

Future sales of our common stock in the public market could adversely affect the price of our common stock.

Sales of substantial amounts of common stock in the public market that are not currently freely tradable, or even the potential for these sales, could have an adverse effect on the market price for the shares of our common stock. These shares include approximately 23.1 million shares purchased by founders and investors and 335,000 warrants at September 15, 2004. Unregistered shares may not be sold except in compliance with Rule 144

promulgated by the SEC, or some other exemption from registration. Rule 144 does not prohibit the sale of these shares but does place conditions and restrictions on their resale, which must be complied with before they can be resold.

Future sales of our common stock in the public market could limit our ability to raise capital.

Sales of substantial amounts of our common stock pursuant to Rule 144, upon exercise or conversion of derivative securities or otherwise, or even the potential of these sales, could also affect our ability to raise capital through the sale of equity securities.

The Company has never paid cash dividends on its common stock and does not intend to do so in the foreseeable future.

Present management and directors may control the election of our directors and all other matters submitted to the stockholders for approval.

Our executive officers and directors, in the aggregate, beneficially own approximately 40% of our outstanding common stock. Further, our Chairman of the Board, Mr. Laird Q. Cagan, Managing Director of Cagan McAfee Capital Partners, LLC ("CMCP"), directly or indirectly, currently owns or controls approximately 7.5 million shares, or approximately 32% of the currently outstanding Common Stock of the Company. Mr. Eric McAfee, also a Managing Director of CMCP, directly or indirectly, currently owns or controls approximately 5.7 million shares, or approximately 25% of the currently outstanding Common Stock of the Company. Collectively, these two managing directors of CMCP directly, or indirectly, currently own or control 13,200,000 shares, or approximately 57% of the currently outstanding Common Stock of the Company. As a result, these holders of our outstanding common stock are able to exercise control over all matters submitted to our stockholders for approval (including the election and removal of directors and any merger, consolidation or sale of all or substantially all of our assets). Accordingly, this concentration of ownership may have the effect of delaying, deferring or preventing a change in control of the Company, impede a merger, consolidation, takeover or other business combination involving the Company or discourage a potential acquirer from making a tender offer or otherwise attempting to obtain control of the Company, which in turn could have an adverse effect on the market price of our common stock.

"Penny stock" regulations may impose certain restrictions on marketability of securities.

The SEC adopted regulations, which generally define "penny stock" to be an equity security that has a market price of less than $5.00 per share. Our common stock may be subject to rules that impose additional sales practice requirements on broker-dealers who sell these securities to persons other than established customers and accredited investors (generally those with assets in excess of $1,000,000, or annual incomes exceeding $200,000 or $300,000 together with their spouse). For transactions covered by these rules, the broker-dealer must make a special suitability determination for the purchase of these securities and have received the purchaser's prior written consent to the transaction.

Additionally, for any transaction, other than exempt transactions, involving a penny stock, the rules require the delivery, prior to the transaction, of a risk disclosure document mandated by the SEC relating to the penny stock market. The broker-dealer also must disclose the commissions payable to both the broker-dealer and the registered representative, current quotations for the securities and, if the broker-dealer is the sole market-maker, the broker-dealer must disclose this fact and the broker-dealer's presumed control over the market. Finally, monthly statements must be sent disclosing recent price information for the penny

stock held in the account and information on the limited market in penny stocks. Consequently, the "penny stock" rules may restrict the ability of broker-dealers to sell our common stock and may affect the ability to sell our common stock in the secondary market.

The market for our Company's securities is limited and may not provide adequate liquidity.

Our common stock is currently traded on the OTC Bulletin Board ("OTCBB"), a regulated quotation service that displays real-time quotes, last-sale prices, and volume information in over-the-counter equity securities. As a result, an investor may find it more difficult to dispose of, or obtain accurate quotations as to the price of, our securities than if the securities were traded on the Nasdaq Stock market, or another national exchange. There are a limited number of active market makers of our common stock. In order to trade shares of our common stock you must use one of these market makers unless you trade your shares in a private transaction. In the twelve months prior to June 30, 2003, the actual trading volume ranged from a low of no shares of common stock to a high of over 341,000 shares of common stock with only 7 days exceeding a trading volume over 100,000 shares (as adjusted for a 40:1 stock split in February 2004). On most days, this trading volume means there is limited liquidity in our shares of common stock. Selling our shares is more difficult because smaller quantities of shares are bought and sold and news media coverage about us is limited. These factors result in a limited trading market for our common stock and therefore holders of our Company's stock may be unable to sell shares purchased should they desire to do so.

ITEM 2. PROPERTIES

Delhi Field.

In late September, 2003, Old NGS purchased a 100% working interest in the Delhi Field by paying $995,000 in cash, issuing non-interest bearing notes for $1,500,000 and assuming a plugging and abandonment reclamation liability in the amount of approximately $302,000, in exchange for the conveyance of all the underlying leasehold interests. The notes are collateralized by a first mortgage on the leasehold interests and are payable to the sellers in twelve equal monthly installments beginning on January 30, 2004. At June 30, 2004, $750,000 remained payable under the notes. In addition to the mortgage, the property is burdened by an aggregate 20% royalty interest.

The Delhi Field was discovered in the 1940's and had been extensively developed over the subsequent decades through the drilling and completion of approximately 450 wells. According to W. D. Von Gonten & Co., the third party reservoir engineering firm that audits our reserves, the field has produced more than 200 million barrels of oil to date, in addition to substantial amounts of gas. Much of the gas production was stripped of gas liquids and re-injected for pressure maintenance. Beginning in the late 1950's, the field was unitized to conduct a pressure maintenance water flood project. Unitization is the process of combining multiple leases into a single ownership entity in order to simplify operations and equitably distribute royalties when common operations are conducted over multiple leases. Drilling operations were completed on primarily 40-acre spacing across the unit's 13,636 acres. A few wells were drilled below the targeted Tuscaloosa sand stone, and many wells were not drilled below the first producing reservoir.

At that time of our acquisition in 2003, production at Delhi averaged approximately 18 BOPD, and no gas was being sold due to a lack of gas processing and transportation facilities. The best producing well, the 161-36, was immediately lost during a periodic sand wash work-over when water from a lower reservoir broke through along the casing and into the producing reservoir.

Currently, at September 15, 2004, the gross productive rate of the field was approximately 58 BOPD, 600 MCFD of gas and 7 BLPD. Current gas sales have been approximately 500 MCFD, as a portion of the produced gas is utilized as compressor, dehydrator and pump engine fuel on site.

The Company has performed, or is planning to perform in the near term, the following significant development work.

Well	BOPD Before	BOPD After	MCFD After	Action
183-3	1	5	5	Re-completion
178-2	4	4	5	Laterally drilled
184-1	4	4	5	Laterally drilled
197-1	4	6	20	Mechanically repaired
197-2	0	65	-65	Restored to production
204-2	0	0	200	Re-completion
198-1	0	0	0	Restore to production — shut-in
184-2	0	0	400	Re-completion from water injection status
210-2	0	Pending	Pending	Restore to production
215-17	0	Pending	Pending	Restore to production
180-1	0	Pending	Pending	Re-completion from water injection status
196-3	0	Pending	Pending	Re-completion of shut-in producer
225-1	0	Pending	Pending	Restore to production
87-2	0	Pending	Pending	Restore to production
203-2	0	Pending	Pending	Restore to production
161-36	10	0	0	Periodic sand wash led to water breakthrough
204-1	SI	0	0	Found collapsed casing

We occupy a leased headquarters containing 2,259 square feet in a modern high-rise office building located in the West Memorial area of Houston, Texas. In April 2003, we extended our lease for three years, without escalators. Other terms include an option for early termination after 18 months, and the right to use furniture and fixtures without cost.

In March of 2004, we installed a leased gas treating and compression facility under a one-year operating lease. The facility was necessary to begin sales of natural gas, which began in July of 2004, thus expanding our revenue base as contemplated by our original plan for the Delhi Field.

NGS maintains insurance on its properties and operations for risks and in amounts customary in the industry. Such insurance includes general liability, excess liability, control of well, operators extra expense and casualty coverage. Not all losses are insured, and the Company retains certain risks of loss through deductibles, limits and self-retentions. NGS does not carry lost profits coverage.

For more complete information regarding current year activities, including oil and gas production, refer to "Management's Discussion and Analysis of Financial Condition and Results of Operations".

Significant Properties, Estimated Proved Oil and Gas Reserves, and Future Net Revenues

NGS engaged W. D. Von Gonten & Co. ("Von Gonten") to perform an independent review of our proved reserves located in the Delhi Field as of July 1, 2004. Von Gonten also previously performed an independent review of our proved reserves at January 1, 2004.

Estimates of reserve quantities and values must be viewed as being subject to significant change as more data about the properties becomes available. All of our existing wells are generally mature wells, originally drilled as many as 58 years ago. As such, they contain older down-hole equipment that is more subject to failure than new equipment. The failure of such equipment or other subsurface failure can result in the complete loss of a well.

At July 1, 2004, natural gas and associated liquids represented 27% and crude oil represented 73% of total proved reserves, denominated in equivalent barrels using a six MCF of gas to one barrel of oil conversion ratio.

The following table sets forth, as of July 1, 2004 and January 1, 2004, information regarding our proved reserves based on the assumptions set forth in Note 10 to the Consolidated Financial Statements where additional reserve information is provided. The average NYMEX prices used to calculate estimated future net revenues were $37.05 and $32.52 per barrel of oil and $6.16 and $6.19 per MMBTU of gas as of June 30, 2004 and December 31, 2003, respectively. The average NYMEX prices used were adjusted for transportation, market differentials and BTU content of gas produced. Amounts do not include estimates of future Federal and State income taxes.

		Oil (bbls)		Gas (Mcf)		Estimated Future Net Revenues			Estimated Future Net Revenues Discounted at 10%
Jul 1, 2004		238,904		508,556	*	$	8,121,711		$	6,320,754
Jan 1, 2004		240,362		778,700		$	10,065,493		$	8,119,670

*: NGL reserves of 5,000 bbls are included in the above gas volumes, at a 6:1 ratio.

Proved Developed reserves total 59% of Total Proved reserves, the balance consisting of Proved Behind Pipe reserves.

The reduction in proved reserves from January 1, 2004 to July 1, 2004 is primarily a result of the reclassification of proved behind pipe reserves associated with the 208-1 well to an other-than-proved category, offset by the addition of proved reserves for the 204-2 and 184-2 wells and increase in proved reserves assigned to the 87-2 well. The reclassification of the 208-1 reserves resulted from review of previously unavailable information that lowered the probability of recovery below the threshold required for proved reserves.

Production, Average Sales Prices and Average Production Costs

Our net production quantities and average price realizations per unit for the fiscal periods set forth below. There were no hedging gains or losses.

	6 months ended June 30, 2004			3 months ended December 31, 2003
Product	Volume	Price		Volume	Price
Gas (Mcf)	123		5.28	—		—
Oil (bbls)	3,180	$	36.95	857	$	28.27

Average production costs, including production taxes, per unit of production (using a six to one conversion ratio of MCF's to barrels) were $38.90 and $92.54 per barrel for the six months ended

June 30, 2004 and the three month period ended December 31, 2003, respectively. The high production costs per barrel are a result of substantial expenses related to general field repair.

Productive Wells and Developed Acreage

Developed acreage at June 30, 2004 totaled 13,636.55 net and gross acres held by a unitization agreement. At June 30, 2004, we owned working interests in 44 net and gross wells consisting of 6 oil wells, 1 gas well, 1 water disposal well and 36 shut-in wells. Subsequent to June 30, we converted two shut-in wells to producing status.

Undeveloped Acreage

All working interest acreage owned by the Company is held by production through a unitization agreement and is previously developed.

Drilling

During fiscal the fiscal year ended June 30, 2004, the Company drilled no new wells.

Subsequent Events

Since June 30, 2004:

•: We have placed on production two additional wells that were previously shut-in in the Delhi Field.
•: We purchased a second property, comprising a 100% working interest in approximately 81 producing oil wells, 8 salt water disposal wells and 54 shut-in wells located in Louisiana, producing approximately 62 BOPD with opportunities for increased production.

See Item 8B, Other Information, for a further discussion.

ITEM 3. LEGAL PROCEEDINGS

We are not a party to any material pending legal proceedings. No such proceedings have been threatened and none are contemplated by NGS.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

There were no matters submitted during the fourth quarter of the fiscal year covered by this report to a vote of security holders through the solicitation of proxies or otherwise.

PART II.

ITEM 5. MARKET FOR THE COMPANY'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS

Our common stock is traded on the OTC Bulletin Board National Association of Securities Dealers Automated Quotation System under the symbol "NGSY" and its predecessor symbol "RLYI". Market quotations shown below were reported by Media General Financial Services and represent prices between dealers, excluding retail mark-up or commissions, and adjusted for the 40:1 stock split that occurred on February 5, 2004.

	Calendar:
	2004				2003
Quarter Ended	High		Low		High		Low
December 31		na		na	$	1.60	$	0.64
September 30		na		na	$	2.60	$	1.20
June 30	$	4.75	$	0.91	$	1.80	$	0.60
March 31	$	3.25	$	0.65	$	1.80	$	0.20

At August 31, 2004, NGS had 241 shareholders of record. We have never paid a cash dividend and we do not expect to pay any cash dividends in the foreseeable future. Earnings, if any, are expected to be reinvested in business activities. No stock has been repurchased since the inception of the Company.

Securities authorized for issuance under equity compensation plans

On August 3, 2004, shareholders approved the adoption of our 2004 Stock Option Plan. No options have been granted under this plan. The purpose of the 2004 Plan is to grant stock options to purchase our common stock to our employees and key consultants

Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights (a)		Weighted-average exercise price of outstanding options, warrants and rights (b)		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c)
Equity compensation plans approved by security holders	600,000(1	)	$	0.1048	3,400,000

Equity compensation plans not approved by security holders	319,932(2	)	$	1.00	—

Total	931,932		$	0.4161	3,400,000

(1): On May 26, 2004, we, as Reality Interactive, Inc., executed an Agreement and Plan of Merger with Natural Gas Systems, Inc., a Delaware corporation (the "Merger"). In connection with the Merger, we assumed the obligations of 600,000 stock options under our newly acquired subsidiary's 2003 Stock Option Plan. No further shares shall be issued under the 2003 Stock Option Plan.
(2): In addition to assuming certain obligations listed in footnote 1 above, in connection with the Merger we also assumed outstanding warrants to purchase 300,000 shares of common stock at an exercise price of $1.00, with a seven year term (warrants). We issued 240,000 of these warrants to CMCP in connection with arranging the merger and 60,000 were issued to CMCP in the placement of 750,000 shares. Subsequently, we issued 19,932 warrants to CMCP in connection with capital raising services on the same terms as the warrants in the preceding sentence.

Recent Sales of Unregistered Securities

On May 26, 2004, we, as Reality Interactive, Inc., executed an Agreement and Plan of Merger with Natural Gas Systems, Inc., a private Delaware corporation ("Old NGS"), whereby the shareholders of Old NGS received 21,749,478 shares of our common stock in exchange for all of the 21,749,748 shares of Old NGS common stock then outstanding. The operations and management of Old NGS became our own, and we changed our name to Natural Gas Systems, Inc. The shares of stock that were issued in the transaction we believe to be exempt from registration under Regulation D promulgated under Section 4(2) of the Securities Act. The issuances were a share for share exchange resulting in a similar investment to that originally contemplated due to the continuation of management and business plan; the recipients in the exchange were accredited investors as defined in Rule 501 of Regulation D promulgated under Section 4(2) of the Securities Act, and took their shares for investment purposes without a view to distribution; they had access to information concerning our Company and our business prospects; there was no general solicitation or advertising for the purchase of our shares; there were no commissions paid; and the securities are restricted pursuant to Rule 144.

In June of 2004, we sold 249,667 shares of our common stock at a price of $1.00 per share (net of warrants exercised at $0.01 per share) in a private offering we believe to be exempt from registration under Regulation D promulgated under Section 4(2) of the Securities Act. These shares were subject to certain registration rights. The sales of stock was to an entity that was an accredited investor, as that term is defined in Rule 501 of Regulation D promulgated under Section 4(2) of the Securities Act and had adequate access to information pertaining to our Company. Furthermore, no advertisements were made and the securities are restricted pursuant to Rule 144. Offering costs consisted of 19,973 warrants exercisable at $1.00 per share until June 2011, and fees of $20,000, both payable to the placement agent.

ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

As used herein, the term "three months ended December 31, 2003" refers to our inception date, September 23, 2003, through December 31, 2003.

Liquidity and Capital Resources

As of June 30, 2004, we had $367,831 of unrestricted cash and negative working capital of $383,352. We incurred losses for the six months period ended June 30, 2004 and three months period ended December 31, 2003 of $1,027,682 and $336,905, respectively. Our negative working capital of $383,352 was adversely impacted by $732,806 of short-term mortgage notes we owe on the Delhi Field, payable in approximately equal monthly installments through December 30, 2004 (the "Delhi Notes" See Note 7 to the financial statements for a further description). Although our cash flow from operations currently approximates our recurring overhead, our cash flow has been, and continues to be, insufficient to cover the Delhi Note payments. Although we are current in our payments on the Delhi Notes, we have relied on additional funding sources to meet these payments since the beginning of 2004. At September 24, 2004, we owed four remaining monthly payments of $125,000 each on the Delhi Notes. At that date, we had cash balances of approximately $256,000 and approximately $176,000 of accounts payable due (excluding deferred fees due CMCP).

Our negative working capital and cash position, as well as our ongoing operating losses, raise concerns about our ability to meet future obligations and fund future operations. Accordingly, management has and continues to expend considerable time and effort to deal with this issue as discussed below. Subsequent to June 30, 2004, we have been working to improve our liquidity using three strategies:

1.: Additional Sales of Common Stock: From June 30 through September 24, 2004 we received $544,734 of additional gross cash proceeds from the private sale of our common stock, before

commissions. We plan to raise funds through additional sales of equity securities in private transactions. Because there can be no assurance that we will be able to do so, we are pursuing borrowing arrangements as discussed below.

2.: Borrowing: On August 11, 2004, we borrowed $475,000 under a short-term secured promissory note (the "Bridge") held by Laird Q. Cagan, the Company's Chairman and major stockholder, secured by a pledge of all of our assets. The loan was earmarked as partial bridge financing for our purchase of the Tullos Urania Field properties for $732,000 on September 3, 2004. The Bridge loan with Mr. Cagan has been amended to delay the repayment until the earlier of (a) July 1, 2005, or (b) the date on which the cumulative gross equity funding after August 14, 2004 reaches $1 million. Terms of the mandatory prepayment have also been amended as more fully described in the original documents filed or incorporated by reference herein. Mr. Cagan is a founding Managing Partner of Cagan McAfee Capital Partners, the financial advisor to the Company that is arranging private equity fundings. If additional funds are not raised, we may not have sufficient funds to repay the Bridge loan or complete our capital expenditure program as currently contemplated.

Since the beginning of 2004, we also began developing relations with at least three commercial banks and several private equity sources that specialize in making loans or investing in oil and gas producers. We believe that our Delhi and Tullos properties could provide sufficient collateral to repay the remaining Delhi Notes in full, as well as providing us with additional development capital aimed at increasing our production from our existing wells according to our original plan. In the event that the collateral is not sufficient to also repay the Bridge loan above, we would likely be required to negotiate those terms further.

3.: Increased Production: We continue to work on increasing cash flow from operations through our Delhi Field and additional acquisition candidates, thereby spreading our overhead, including significant expenses of being a public company, over a larger revenue base. On September 3, 2004, we closed the purchase of producing properties in the Tullos Urania Field, located close to our Delhi Field operations in Northern Louisiana. We believe that net cash flow from operations at our Tullos property currently exceeds $30,000 per month. We also believe that opportunities exist to increase Tullos production with relatively small amounts of additional capital expenditures.

We are pursuing additional acquisition candidates meeting our targeted requirements.

Because earnings, if any, are anticipated to be reinvested in operations, cash dividends are not expected to be paid in the foreseeable future. Commitments for future capital expenditures were not material at year-end. The Company has no defined benefit plans and no obligations for post retirement employee benefits.

Product Prices and Production

Refer to Item 1, "Markets and Customers", for discussion of oil and gas prices and marketing.

Although product prices are key to our ability to operate profitably and to budget capital expenditures, they are beyond the Company's control and are difficult to predict. Although we have not entered into any product price hedges, we may do so. Gas sales are completed on a BTU basis and the gas pipeline measures the BTU content at the delivery point. The gas produced at the Delhi Field is high BTU, with over 1100 BTU per cubic foot of gas from the dry gas wells, and over 1300 BTU in gas associated with the oil wells. Due to the low initial production volumes, the Company utilizes a J-T gas processing unit that strips out most of the heavier liquids, in accordance with the sales pipeline criteria. However, the J-T unit is not as efficient as more costly methods such as cryogenic separation, thus the sales gas heat content of 1117 BTU per cubic foot (actual determination for the month of August, 2004)

currently is being delivered to the gas sales pipeline is a higher BTU content than the standard of 1000 BTU per cubic foot. When gas production volume increases to a sufficient level, we may switch to a more efficient processing unit.

Our net production for the three month period ended December 31, 2003 was 857 BBLs, and, the average price received was $28.27 per BBL. For the six month period ended June 30, 2004, our net production was 3,180 BBLs and 123 MCF of natural gas, with average prices received of $36.95 per BBL and $5.28 per MCF. Increases in oil and natural gas volumes for the six months period ended June 30, 2004 over those for the three months ended December 31, 2003 were a result of more months in the period and the successful work-over and restoration to production of several wells.

Refer to Item 2, "Properties", for disclosures regarding reserve values.

Oil and Gas Activities

General

Reserves

Refer to Item 2, "Properties, General, Estimated Proved Oil and Gas Reserves and Future Net Reserves", for information regarding oil and gas reserves.

Results of Operations

During the six months period ended June 30, 2004, we generated revenues of $118,158. Revenues for the three months period ended December 31, 2003 were $24,229. Average daily production increased from 9 BOEPD (857 BOE total) for the three months period ended December 31, 2004, to 21 BOEPD (3,831 BOE total) during the 6 months period ended June 30, 2004. The increase in production is primarily a result of adding the 197-2 well to production. Prior to June 30, 2004, the 197-2 well was limited in rate due to restrictions on the amount of associated gas that could be vented, combined with down time caused by repeated workovers due to sand production. Subsequent to June 30, 2004, the pump was raised 300' and the well has been producing at a more consistent rate without sand problems.

Also subsequent to June 30, 2004, we began daily sales of gas through the refurbished gas gathering pipeline and gas treating and processing facility, allowing full production of oil wells and full production of the 204-2 well, a dry gas producer. Since gas sales began, the 204-2 well has been producing in excess of 150 MCFD. Please see Note 10, Subsequent Events, for wells placed on production subsequent to June 30, 2004.

Operating expenses were $79,305 or $92.54 per BOE, for the three months ended December 31, 2003 and $149,001 or $38.90 per BOE, for the six months ended June 30, 2004. Operating expenses for both periods are high due to the unusual level of workovers needed to control sand production in the 197-2 well (now believed to be corrected) and due to well upsets resulting from frequent production shut-ins caused by the three month process of getting the gas treating facilities working.

General and Administrative costs were $239,093 for the three months ended December 31, 2003 and $542,761 for the six months ended June 30, 2004. The costs included the addition of a second executive officer late in 2003 and the expensing of stock-based compensation in the amount of $50,400 for the three months ended December 31, 2003, and $108,614 for the six months ended June 30, 2004.

Merger fees and expenses related to the merger of Old NGS into a subsidiary of Reality were estimated to be $370,000 for the six month period ended June 30, 2004.

Critical Accounting Policies and Estimates

Accounting for Oil and Gas Property Costs. As more fully discussed in Note 3 to the consolidated financial statements, the Company (i) follows the full cost method of accounting for the costs of its oil and gas properties, (ii) amortizes such costs using the units of production method, and (iii) applies a quarterly full cost ceiling test. Adverse changes in conditions (primarily oil or gas price declines) could result in permanent write-downs in the carrying value of oil and gas properties as well as non-cash charges to operations, but would not affect cash flows.

Estimates of Proved Oil and Gas Reserves. An independent petroleum engineer annually estimates 100% of our proved reserves. Reserve engineering is a subjective process that is dependent upon the quality of available data and the interpretation thereof. In addition, subsequent physical and economic factors such as the results of drilling, testing, production and product prices may justify revision of such estimates. Therefore, actual quantities, production timing, and the value of reserves may differ substantially from estimates. A reduction in proved reserves would result in an increase in depreciation, depletion and amortization ("DD&A") expense.

Estimates of Asset Retirement Obligations. In accordance with SFAS No 143, we make estimates of future costs and the timing thereof in connection with recording our future obligations to plug and abandon wells. Estimated abandonment dates will be revised in the future based on changes to related economic lives, which vary with product prices and production costs. Estimated plugging costs may also be adjusted to reflect changing industry experience. Increases in operating costs and decreases in product prices would increase the estimated amount of the obligation and increase DD&A expense. Cash flows would not be affected until costs to plug and abandon were actually incurred.

This Form 10-KSB includes certain statements that may be deemed to be "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. All statements included in this Form 10-KSB, other than statements of historical facts, address matters that the Company reasonably expects, believes or anticipates will or may occur in the future. Such statements are subject to various assumptions, risks and uncertainties, many of which are beyond the control of the Company. Investors are cautioned that any such statements are not guarantees of future performance and that actual results or developments may differ materially from those described in the forward-looking statements. The Company bases its forward-looking statements on information currently available and it undertakes no obligation to update them.

ITEM 7. FINANCIAL STATEMENTS

Index to Consolidated Financial Statements

Independent Auditors' Report

Consolidated Balance Sheets as of June 30, 2004 and December 31, 2003

Consolidated Statements of Operations for the Six Months ended June 30, 2004 and the Three Months ended December 31, 2003

Consolidated Statements of Stockholders' Equity as of June 30, 2004

Consolidated Statements of Cash Flows for the Six Months ended June 30, 2004 and the Three Months ended December 31, 2003

Notes to Consolidated Financial Statements

NATURAL GAS SYSTEMS, INC. AND SUBSIDIARIES

Consolidated Balance Sheets

				June 30, 2004			December 31, 2003
ASSETS
Current Assets
	Cash and short-term investments			$	367,831		$	830,312
	Receivables				24,387			56,837
	Inventories				115,859			109,216
	Prepaid expenses				69,067			25,930
	Retainers and deposits				5,000			210,000

			Total current assets		582,144			1,232,295
Oil and gas properties being amortized (full cost method)					3,075,438			2,971,468
Oil and gas properties not being amortized					105,225			—
Less: accumulated amortization					(55,509	)		(13,960	)

			Net oil and gas properties		3,125,154			2,957,508
Furniture, fixtures and equipment, at cost					3,091			3,091
Less: accumulated depreciation					(1,159	)		(386	)

			Net furniture, fixtures and equipment		1,932			2,705
Other assets (cash balances earmarked for bonding requirements)					301,835			301,835

			Total Assets	$	4,011,065		$	4,494,343

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
	Accounts payable			$	139,188		$	114,188
	Accrued liabilities				50,073			41,118
	Notes payable				776,235			1,437,073
	Production taxes payable				—			665

			Total current liabilities		965,496			1,593,044
Deferred plugging and abandonment liabilities					311,442			305,004
Stockholders' equity:
	Common stock, par value $0.001 per share; 100,000,000 shares authorized, 22,945,406 and 21,772,362 shares issued and outstanding as of June 30, 2004 and December 31, 2003, respectively				22,945			21,772
	Additional paid-in capital				4,453,905			3,398,178
	Deferred stock based compensation				(378,136	)		(486,750	)
	Accumulated deficit				(1,364,587	)		(336,905	)

		Total stockholders' equity			2,734,127			2,596,295

		Total liabilities and stockholders' equity		$	4,011,065		$	4,494,343

See accompanying notes to consolidated financial statements.

NATURAL GAS SYSTEMS, INC. AND SUBSIDIARIES

Consolidated Statements of Operations

			Six Months Ended June 30, 2004			For the Period From September 23, 2003 (Inception) to December 31, 2003
Revenues:
	Oil sales		$	117,509		$	24,229
	Gas sales			649			—

		Total revenues		118,158			24,229
Expenses:
	Operating costs			134,420			76,303
	Production taxes			14,581			3,002
	Depletion			41,549			13,960
	Reverse-merger fees and expenses			370,000			—
	General and administrative			542,761			239,093

		Total expenses		1,103,311			332,358

Loss from operations				(985,153	)		(308,129	)
Other revenues and expenses:
	Interest income			4,093			1,148
	Interest expense			(46,622	)		(29,924	)

		Total other revenues and expenses		(42,529	)		(28,776	)

Net loss			$	(1,027,682	)	$	(336,905	)

Income (loss) per common share:
	Basic and diluted		$	(0.05	)	$	(0.02	)

Weighted average number of common shares, basic and diluted				22,057,614			20,091,720

See accompanying notes to consolidated financial statements.

NATURAL GAS SYSTEMS, INC. AND SUBIDIARIES

Consolidated Statements of Changes in Stockholders' Equity

For the Period From September 23, 2003 (Inception) to June 30, 2004

		Shares	Dollars		Additional Paid-in Capital		Deferred			Accumulated Deficit			Total Stockholders' Equity
Balances, September 23, 2003		—	$	—	$	—	$	—		$	—
Sales of common stock		21,772,362		21,772		2,861,028		—			—			2,882,800
Stock-based compensation		—		—		537,150		(486,750	)		—			50,400
Net loss		—		—		—		—			(336,905	)		(336,905	)

Balances, December 31, 2003		21,772,362		21,772		3,398,178		(486,750	)		(336,905	)		2,596,295
Sales of common stock before merger		923,377		923		825,977		—			—			826,900
Sales of common stock after merger		249,667		250		229,750		—			—			230,000
	Deferred compensation	—		—		—		108,614			—			108,614
Net loss		—		—		—		—			(1,027,682	)		(1,027,682	)

Balances, June 30, 2004		22,945,406	$	22,945	$	4,453,905	$	(378,136	)	$	(1,364,587	)	$	2,734,127

See accompanying notes to consolidated financial statements.

NATURAL GAS SYSTEMS, INC. AND SUBIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

					Six Months ended June 30, 2004			For the Period From September 23, 2003 (Inception) to December 31, 2003
Operating activities:
	Net loss				$	(1,027,682	)	$	(336,905	)
	Adjustments to reconcile net loss to net cash provided (used) by operating activities:
		Depletion				41,549			13,960
		Depreciation				773			386
		Stock-based compensation expense				108,614			50,400
		Accretion of debt discount				—			29,924
		Changes in assets and liabilities:
			Accretion of deferred plugging and abandonment
				Liability		6,438			3,169
			Accounts receivable			32,450			(28,762	)
			Inventories			(6,643	)		(109,216	)
			Accounts payable			24,999			114,188
			Other current liabilities			8,289			41,783
			Prepaid expenses			(43,137	)		(25,930	)
			Retainers and deposits			205,000			(210,000	)

				Net cash used by operating activities		(649,350	)		(457,003	)
Investing activities:
	Capital expenditures for oil and gas properties					(209,194	)		(1,290,560	)
	Capital expenditures for furniture, fixtures, and equipment					—			(3,090	)
	Cash restricted for Delhi bonding requirements					—			(301,835	)

				Net cash used in investing activities		(209,194	)		(1,595,485	)
Financing activities:
	Payments on notes payable					(710,327	)		—
	Proceeds from notes payable					49,490			—
	Proceeds from issuance of common stock					1,056,900			2,882,800

				Net cash provided by financing activities		396,063			2,882,800

Net (decrease) increase in cash						(462,481	)		830,312
Cash and cash equivalents, beginning of period						830,312			—

Cash and cash equivalents, end of period					$	367,831		$	830,312

Supplemental Cash Flow Information:
	Interest paid				$	46,622			—
	Taxes paid					—			—
Non-cash transactions:
	Seller note issued to acquire properties, net of discount					—		$	1,407,049
	Assumption of plugging and abandonment liability					—		$	301,835

See accompanying notes to consolidated financial statements.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2004

NATURAL GAS SYSTEMS, INC. AND SUBSIDIARIES

1. Company's Business

Reality Interactive, Inc. ("Reality"), a Nevada corporation that traded on the OTC Bulletin Board under the symbol RLYI.OB, and the predecessor of Natural Gas Systems, Inc., was incorporated on May 24, 1994 for the purpose of developing technology-based knowledge solutions for the industrial marketplace. On April 30, 1999, Reality ceased business operations, sold substantially all of its assets and terminated all of its employees. Subsequent to ceasing operations, Reality explored other potential business opportunities to acquire or merge with another entity, while continuing to file reports with the SEC. During the most recent two years, Reality represented that it had not conducted any operations and had minimal assets and liabilities.

On May 26, 2004, Natural Gas Systems, Inc., a privately owned Delaware corporation formed in September of 2003 ("Old NGS"), was merged into a wholly owned subsidiary of Reality and Reality changed its name to Natural Gas Systems, Inc. On the effective date of the merger, Laird Q. Cagan was elected as Chairman of the Board of Directors of Reality and Robert S. Herlin and Sterling H. McDonald, the CEO and CFO of Old NGS, were elected CEO and CFO of Reality, respectively. The corporation was renamed Natural Gas Systems, Inc. (the "Company" or "NGS") and adopted a June 30 fiscal year end.

Headquartered in Houston, Texas, Natural Gas Systems, Inc. is a development stage petroleum company engaged primarily in the acquisition, exploitation and development of properties for the production of crude oil and natural gas from underground reservoirs. NGS acquires established oil and gas properties and exploits them through the application of conventional and specialized technology to increase production, ultimate recoveries, or both. At June 30, 2004, NGS conducted operations through its 100% working interest in the Delhi Field in Louisiana.

All regulatory filings and other historical information including stock prices prior to May 26, 2004 apply to Reality, the predecessor of the Company. NGS trades on the OTC Bulletin Board under the symbol NGSY.OB. All stock information is adjusted to reflect Reality's 40:1 reverse stock split effected prior to the merger with NGS.

2. Significant Risks and Uncertainties

Preparation of the Company's financial statements requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities and contingencies as of the balance sheet date, and the reported amount of revenues and expenses during the reporting period. On an ongoing basis, management reviews its estimates, including those related to litigation, environmental liabilities, income taxes, abandonment costs and the determination of proved reserves. Changes in circumstances may result in revised estimates and actual results may differ from those estimates.

The Company's business makes it vulnerable to changes in crude oil and natural gas prices. Such prices have been volatile in the past and can be expected to be volatile in the future. This volatility can dramatically affect cash flows and proved reserves, since price declines reduce the estimated quantity of proved reserves and increase annual amortization expense (which is based on proved reserves). Other risks related to proved reserves, revenues, and cash flows include the Company's current reliance on the concentration of a few wells. The reserve report dated July 1, 2004, identified six wells that make

up approximately 60% of the Company's future net cash flows, discounted at 10% per annum. At July 31, 2004, approximately 85% of the Company's production was derived from three wells.

3. Summary of Significant Accounting Policies

Principles of Consolidation—The consolidated financial statements include the Company and its subsidiaries. All material intercompany accounts and transactions have been eliminated.

Oil and Gas Properties and Furniture, Fixtures and Equipment—The Company follows the full cost method of accounting for its investments in oil and natural gas properties. All costs incurred in the acquisition, exploration and development of oil and natural gas properties, including unproductive wells, are capitalized. Included in capitalized costs are general and administrative costs that are directly related to acquisition, exploration and development activities. Proceeds from the sale of oil and natural gas properties are credited to the full cost pool, unless the sale involves a significant quantity of reserves, in which case a gain or loss is recognized. Under the rules of the Securities and Exchange Commission ("SEC") for the full cost method of accounting, the net carrying value of oil and natural gas properties, reduced by the asset retirement obligation, is limited to the sum of the present value (10% discount rate) of the estimated future net cash flows from proved reserves, based on the current prices, plus the lower of cost or estimated fair market value of unproved properties adjusted for related income tax effects.

Capitalized costs of proved oil and natural gas properties are depleted on a unit of production method using proved oil and natural gas reserves. Costs depleted include net capitalized costs subject to depletion and estimated future dismantlement, restoration and abandonment costs.

Equipment, which includes computer equipment, hardware and software and furniture and fixtures, is recorded at cost and is generally depreciated on a straight-line basis over the estimated useful lives of the assets, which range from two to seven years.

Repairs and maintenance are charged to expense as incurred.

Statement of Cash Flows—For purposes of the statements of cash flows, cash equivalents include highly liquid financial instruments with maturities of three months or less as of the date of purchase.

Concentrations of Credit Risk—All of the Company's trade receivables are due from one purchaser. Accounts receivable are not collateralized.

Revenue Recognition—The Company recognizes oil and natural gas revenue from its interests in producing wells as oil and natural gas is sold.

Accounting for Reverse Merger—The Company accounts for its reverse-merger in accordance with Staff Accounting Bulletin ("SAB") Topic 2A. Generally, the staff of the Division of Corporate Finance considers reverse-mergers into public shells to be capital transactions in substance, rather than business combinations. That is, the transaction is equivalent to the issuance of stock by the private company for the net monetary assets of the shell corporation, accompanied by a recapitalization.

Under this treatment, post reverse-acquisition comparative historical financial statements are those of the "legal acquiree" (i.e., the "accounting acquirer"), with appropriate disclosure concerning the change in the capital structure effected at the acquisition date. In the Company's case, the historical financial statements are those of the oil and gas operations of Old NGS, except that the Consolidated Statement

of Changes in Stockholder's Equity reflect the activity of Old NGS prior to the merger. All share and per share amounts have been adjusted to reflect the conversion ratio of shares exchanged between Reality and Old NGS.

Also, in accordance with SAB Topic 2A, transaction costs incurred for the reverse-merger, such as legal fees, investment banking fees and the like, may be charged directly to equity only to the extent of the cash received, while all costs in excess of cash received should be charged to expense. Accordingly, since no cash was received, $370,000 in transaction fees were expensed in the Company's accompanying financial statements.

Stock Options—As permitted by SFAS No. 123, "Accounting for Stock Based Compensation," the Company follows the accounting requirements for stock options and stock-based awards contained in Accounting Principles Board Opinion No. 25, "Accounting for stock Issued to Employees," and related Interpretations and consensus of the Emerging Issues Task Force in terms of measuring compensation expense.

SFAS 123, "Accounting for Stock-Based Compensation," as amended by SFAS 148, "Accounting for Stock-Based Compensation—Transition and Disclosure," established accounting and disclosure requirements using a fair value-based method of accounting for stock-based employee compensation plans. The Company accounts for stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board Opinion 25, "Accounting for Stock Issued to Employees" ("APB 25").

Fair Value of Financial Instruments—Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and seller notes. The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the highly liquid nature of these short-term instruments. The fair values of the seller notes approximates their carrying amounts as of June 30, 2004, based upon interest rates currently available to us for borrowings with similar terms.

New Accounting Pronouncements—During December 2003, the FASB issued Interpretation No. 46R, "Consolidation of Variable Interest Entities" ("FIN 46"), which requires the consolidation of certain entities that are determined to be variable interest entities ("VIE's"). An entity is considered to be a VIE when either (i) the entity lacks sufficient equity to carry on its principal operations, (ii) the equity owners of the entity cannot make decisions about the entity's activities or (iii) the entity's equity neither absorbs losses or benefits from gains. NGS owns no interest in variable interest entities, and therefore this new interpretation has not affected the Company's consolidated financial statements.

4. Acquisitions

In September 2003, Old NGS completed the acquisition of a 100% working interest in the Delhi Field. The acquisition closed on September 25, 2003, whereby Old NGS paid $995,000 in cash, issued a purchase money mortgage for $1,500,000 (See Note 7, Notes Payable, for a description of the mortgage) and assumed a plugging and abandonment reclamation liability in the amount of approximately $302,000 (see Note 5, Asset Retirement Obligations), in exchange for the conveyance of all the underlying leasehold interests. In addition to the mortgage, the property is burdened by an aggregate 20% royalty interest.

On May 26, 2004, Reality Interactive, Inc., a publicly traded Nevada corporation ("Reality"), executed an Agreement and Plan of Merger with Natural Gas Systems, Inc., a private Delaware corporation

("Old NGS"), whereby the shareholders of Old NGS received 21,749,478 shares of common stock of Reality, in exchange for all of the 21,749,748 shares of Old NGS common stock then outstanding. The operations and management of Old NGS became our own, and Reality's name was changed to Natural Gas Systems, Inc., a Nevada corporation (the "Company" or "NGS"). Immediately prior to the closing of the merger, Reality had virtually no operations, assets or liabilities.

5. Asset Retirement Obligations

When an oil or gas property ceases economic production, the Company dismantles and removes all surface equipment, plugs the wells and restores the property's surface in accordance with various regulations and agreements before abandoning the property. The state of Louisiana requires operators of oil and gas properties to secure plugging, abandonment and reclamation liabilities with financial collateral in favor of the state. In the case of the Delhi Field, the previous owner had established a Site Specific Trust Fund (SSTA Account) that is considered a fully funded liability by the state of Louisiana. Pursuant to the Company's agreement to purchase the Delhi Field in September of 2003, NGS agreed to replace the seller's collateral on the SSTA Account within 120 days of closing. During the six months ended June 30, 2004, NGS replaced the seller's collateral by posting a letter of credit in the face amount of $301,835, fully collateralized by a certificate of deposit issued on Wells Fargo Bank. These restricted cash equivalents are carried as "Other Assets" in the Company's balance sheet.

In accordance with FAS 143, the Company has recorded an estimated asset retirement obligation ("ARO") for its Delhi Field of approximately $302,000, of which $274,000 relates to the Company's wells and $28,000 relates to wells operated by the Company for a third party. Accordingly, the Company has recorded an asset retirement obligation in the amount of $302,000, with an offsetting $274,000 charge to the full cost pool and a $28,000 receivable due from the 3rd party at December 31, 2003. The receivable was collected during the six months ended June 30, 2004.

Also in accordance with FAS 143, the Company provides accretion expense on all ARO liabilities. For the Delhi Field, NGS uses the 10-year constant maturity Treasury yield of 4.27% available at September 30, 2003, which equates to 1.05% per quarter.

The following table describes the change in the Company's asset retirement obligations for the period from September 23, 2003 (inception) to June 30, 2004:

Asset retirement obligation at September 23, 2003	$	301,835
Accretion expense for 2003		3,169

Asset retirement obligation at December 31, 2003		305,004
Accretion expense for 2004		6,438

Asset retirement obligation at June 30, 2004	$	311,442

6. Oil and Gas Properties

Depletion expense for the period from September 23, 2003 (inception) to December 31, 2003 and for the six months ended June 30, 2004 totaled $13,960 and $41,549, respectively.

During 2003, no costs were excluded from amortization. For the six months ended June 30, 2004, $105,225 of costs were not being amortized, pending the closing or abandonment of property acquisitions under active consideration.

7. Notes Payable

In September 2003, the Company issued $1,500,000 of notes payable in connection with its acquisition of the Delhi Field. The notes were collateralized by a first mortgage on the Company's Delhi field and are payable to the sellers in twelve equal monthly installments beginning on January 30, 2004. Although the notes bear no interest, the Company has imputed interest at 8% per annum, thus resulting in an initial recorded principal amount of $1,407,049. At December 31, 2003, the balance of the notes payable was $1,436,973, including $29,924 of imputed interest. At June 30, 2004, the principal balance outstanding was $732,807.

In May 2004, the Company borrowed $49,490 to finance 70% of its Director and Officer's liability insurance premiums. The note requires eight level mortgage-amortizing payments in the amount of $5,350 per month, including 7% interest per annum, with the first payment due on June 25, 2004. At June 30, 2004, the principal outstanding balance of the note was $43,429.

8. Common Stock and Stock Options

Common Stock

At December 31, 2003, Reality had issued and outstanding 256,598 shares of its $0.001 par value common stock. From January 1, 2004, up to, but not including, the merger closing on May 26, 2004, Reality issued 689,663 of its $0.001 par value common shares, net of cancellations and redemptions. At the closing of the merger on May 26, 2004, Reality issued 21,749,478 of its $0.001 par value common shares in exchange for all of the 21,749,478 issued and outstanding $0.001 par value common shares of Old NGS.

During 2003, Old NGS issued 18,000,000 common shares as founder's capital at $0.001 per share, and sold 2,864,600 of its $0.001 par value common shares at $1.00 per share through a private equity offering to accredited investors. Prior to the merger closing in 2004, Old NGS sold an additional 884,878 of its $0.001 par value common shares to accredited investors for $886,900 gross proceeds, less $60,000 in commissions equal to 8% of the gross cash proceeds and the issuance of 7 year term warrants equal to 8% of the shares issued, for the account of Chadbourn Securities, Inc. and Laird Q. Cagan, an affiliate of the Company as described in Footnote 9 on Related Party Transactions.

Since the merger closing through June 30, 2004, the Company sold 249,667 shares of its $0.001 par value common shares for gross proceeds of $250,000, less $30,000 in commissions and the same warrant structure described above for the account of Chadbourn Securities, Inc. and Laird Q. Cagan.

At June 30, 2004, the Company had 22,945,406 issued and outstanding shares of common stock.

See Note 11, Subsequent Events, for information on additional sales of common stock since June 30, 2004.

Options

Old NGS adopted a stock option plan in 2003 (the "2003 Plan"). The purpose of the 2003 Plan was to offer selected individuals an opportunity to acquire a proprietary interest in the success of Old NGS, or to increase such interest, by purchasing shares of the Old NGS' common stock. The 2003 Plan provided both for the direct award or sale of shares and for the grant of options to purchase shares in an aggregate amount not to exceed 4,000,000 shares. Options granted under the Plan included nonstatutory options as well as incentive stock options intended to qualify under Section 422 of the Code. Options granted under the 2003 Plan were assumed by Reality Interactive, Inc., predecessor to the Company. No further shares will be granted under the 2003 Stock Option Plan.

At June 30, 2004, options totaling 600,000 shares of the Company's stock had were outstanding, having been granted in 2003 by Old NGS and assumed in 2004 by the Company, subject to various vesting requirements. Options to purchase 250,000, 250,000 and 100,000 shares were granted to Messrs. Herlin, McDonald and Lee (counsel to the Company), respectively. Mr. Herlin's options are committed for subsequent cancellation and re-issuance as warrants to Tatum Partners, in consideration of its services agreement with the Company. These options were accounted for under APB 25, with respect to Messrs. Herlin and McDonald, and under FASB 123 with respect to Messrs. Lee, and gave rise to $537,150 of Company expense to be recognized over the respective vesting periods of the options.

On August 3, 2004, the Company adopted its 2004 Stock Option Plan (the "2004 Plan"). The purpose of the 2004 Plan is to offer selected individuals an opportunity to acquire a proprietary interest in the success of the Company, or to increase such interest, by purchasing shares of the Company's common stock. The 2004 Plan provides both for the direct award or sale of shares and for the grant of options to purchase shares in an aggregate amount not to exceed 4,000,000 shares. Options granted under the 2004 Plan may include nonstatutory options as well as incentive stock options intended to qualify under Section 422 of the Code.

No options were issued during the six months ended June 30, 2004. However, 200,000 options have been authorized, but not issued, to two members of the Board of Directors of the Company.

A reconciliation of reported loss as if the Company used the fair value method of accounting for stock-based compensation has not been provided as the fair value of options computed under FASB 123 was essentially the same as the amount determined in accordance with APB 25.

Fair value was estimated at the date of grant using the Black-Scholes options pricing model with the following weighted average assumptions: risk-free interest rate of approximately 2.5%; dividend yield of 0%; volatility factor of 1.31; and a weighted-average expected life of three years. These assumptions resulted in a weighted average grant date fair value of $.99. For purposes of the pro forma disclosures, the estimated fair value is amortized to expense over the awards' vesting period.

The Black-Scholes option valuation model was developed for use in estimating the fair value of traded options which have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of highly subjective assumptions including the expected stock price volatility. Because the Company's employee stock options have characteristics significantly different from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, in management's opinion, the existing models do not necessarily provide a single measure of the fair value of its employee stock options. At June 30, 2004, 3,400,000 shares were available for grant under the plans. A summary of options transactions for the period from September 23, 2003 (inception) to June 30, 2004 follows:

		Number of Shares	Weighted Average Exercise Price
Outstanding at September 23, 2003			$	—
	Granted	600,000		0.10

	Exercised	—		—
	Canceled	—		—

Outstanding at December 2003		600,000	$	0.10

	Granted	—		—
	Exercised	—		—
	Canceled	—		—

Outstanding at June 30, 2004		600,000	$	0.10

Shares exercisable at June 30, 2004		153,122	$	0.05

	Options Outstanding
Range of Exercisable Prices	Outstanding at June 30, 2004	Weighted Average Exercise Price	Exercisable June 30, 2004
.001	350,000	.001	121,872
.25	250,000	.25	31,250

The weighted average remaining contractual life of options outstanding at June 30, 2004, was approximately 38 months. The weighted average grants date fair value of the options granted in 2003 was $.89 per share. The options vest as follows: 2004 - 150,000; 2005 - 150,000; 2006 - 150,000; and 2007 - 150,000.

Warrants

At June 30, 2004, outstanding warrants to purchase the Company's $0.001 par value common shares were as follows:

	Warrants Outstanding
Holder	Range of Exercisable Prices		Outstanding at June 30, 2004	Exercisable June 30, 2004 Thru 2011
Cagan McAfee Capital Partners, LLC	$	1.00	240,000	240,000
Laird Q. Cagan	$	1.00	75,935	75,935
Chadbourn Securities, Inc.	$	1.00	3,997	3,997
Total			319,932	319,932

The warrants above were issued for services rendered for the merger and the sale of the Company's common shares. Laird Q. Cagan and Cagan McAfee Capital Partners ("CMCP") are affiliates of the Company. We issued 240,000 of these warrants to CMCP in connection with arranging the merger. We issued 79,932 to Laird Q. Cagan and Chadbourn Securities, Inc., in connection with capital raising services.

9. Related Party Transactions

Laird Cagan, Chairman of the Board of the Company, is a Managing Director of Cagan McAfee Capital Partners, LLC ("CMCP"). CMCP performs financial advisory services to the Company pursuant to a written agreement and is paid a monthly retainer of $15,000. In addition, Mr. Cagan is a registered representative of Chadbourn Securities, Inc. ("Chadbourn"), the Company's placement agent in private equity financings. Pursuant to the Agreement between the Company, Mr. Cagan, and Chadbourn, the Company pays a cash fee equal to 8% of gross equity proceeds and warrants equal to 8% of the shares purchased. During 2003, the Company expensed and paid CMCP $32,500 for monthly retainers.

In connection with the founding of the Company, 18,000,000 shares of NGS common stock were directly and indirectly purchased by various parties as founder's shares, including, 1,000,000 shares by Robert S. Herlin as an incentive to perform as the Company's President and CEO; 1,000,000 shares by Liviakis Financial Communications, Inc., the Company's investor relations firm; 7,500,000 shares by Laird Q. Cagan, the Company's Chairman and Managing Director of CMCP; and 5,700,000 by Eric M. McAfee, Managing Director of CMCP, and 450,000 by John Pimentel, a member of the Company's Board of Directors.

During the six months ended June 30, 2004 the Company has expensed $90,000 in monthly retainers, $60,000 of which remains unpaid at June 30, 2004, and charged $80,000 to stockholder's equity as a reduction of the proceeds from common stock sales in the amount of $1,000,000. The $80,000 paid to Chadbourn Securities and Laird Q. Cagan was for commissions from the sale of the common stock. Also during the six months ended June 30. 2004 NGS issued warrants to purchase 319,932 shares of Common Stock to CMCP, Chadbourn Securities and Laird Q. Cagan in connection with arranging the merger, (240,000 warrants) and placement of 999,145 common shares (79,932 warrants). These warrants have a $1.00 exercise price and a seven year term.

Eric McAfee, also a Managing Director of Cagan McAfee Capital Partners, has served as Vice Chairman of the Board of Verdisys, Inc., the provider of certain horizontal drilling services to the Company. Subsequently in 2004, Mr. McAfee resigned from the Board of Directors of Verdisys, but continues to hold shares in both companies. Mr. McAfee has represented to the Company that he is also a 50% owner of Berg McAfee Companies, LLC, which owns approximately 30% of Verdisys, Inc. NGS paid $130,000 to Verdisys during 2003 and $25,960 during 2004 for horizontal drilling services.

Subsequent to June 30, 2004, Laird Cagan, Chairman of the Board of the Company, loaned the Company $475,000 as partial bridge financing for the acquisition of the Tullos Urania Field. See Footnote 11, Subsequent Events, for a further explanation.

10. Supplemental Oil and Gas Disclosures (unaudited)

Costs Incurred in Oil and Gas Producing Activities

		Six Months Ended June 30, 2004		For the Period From September 23, 2003 (Inception) to December 31, 2003
Property acquisition costs:
	Proved	$	6,855	$	2,363,716
	P&A liability assumed		—		273,760
	Unproved		105,225		—
Exploration costs			—		—
Development costs			97,114		333,992

Total Property Acquisition Costs		$	209,194	$	2,971,468

Results of Operations for Oil and Gas Producing Activities

	Six Months Ended June 30, 2004			For the Period From September 23, 2003 (Inception) to December 31, 2003
Oil and gas sales	$	118,158		$	24,229
Production costs		(134,420	)		(76,303	)
Production taxes		(14,581	)		(3,002	)
Depletion		(41,549	)		(13,960	)

Results of operations for oil and gas producing activities (excluding corporate overhead and financing costs)	$	(72,392	)	$	(69,036	)

Proved Developed and Undeveloped Reserves
prepared by W.D. Von Gonten & Co. Petroleum Engineers

The following table sets forth the net proved reserves of the Company as of July 1, 2004, and the changes therein for the period from September 23, 2003 (inception) to July 1, 2004. The reserve

information was reviewed by W.D. Von Gonten & Co., independent petroleum engineers. All of the Company's oil and gas producing activities are located in the United States.

	Oil (bbls)		Gas (mcf)
September 23, 2003	—		—
Purchases of minerals in place	241,219		778,700
Extensions and discoveries	—		—
Production	(857	)	—

Sales of minerals in place	—		—
December 31, 2003	240,362		778,700

Purchases of minerals in place
Extensions, discoveries and revisions	2,352		(270,021	)
Production	(3,810	)	(123	)

Sales of minerals in place	—		—

July 1, 2004	238,904		508,556	*
Proved developed reserves:
December 31, 2003	240,400		778,700
July 1, 2004	238,900		508,556	*

*: Includes 5,000 BBL of NGL's converted at 6 BBLs / MCF

Standardized Measure of Discounted Future Net Cash Flows
at December 31, 2003 and June 30, 2004

The information that follows has been developed pursuant to SFAS No. 69 and utilizes reserve and production data prepared or reviewed by independent petroleum consultants. Reserve estimates are inherently imprecise and estimates of new discoveries are less precise than those of producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available.

The estimated discounted future net cash flows from estimated proved reserves are based on prices and costs as of the date of the estimate unless such prices or costs are contractually determined at such date. Actual future prices and costs may be materially higher or lower. Actual future net revenues also will be affected by factors such as actual production, supply and demand for oil and natural gas, curtailments or increases in consumption by natural gas purchasers, changes in governmental regulations or taxation and the impact of inflation on costs. Future income tax expense has been reduced for the effect of available net operating loss carryforwards.

			Six Months Ended June 30, 2004			For the Period From September 23, 2003 (Inception) to December 31, 2003
Future cash inflows			$	11,549,850		$	13,318,169
Future production costs				(2,978,139	)		(2,895,677	)
Future development costs				(450,000	)		(357,000	)
Future income taxes				(1,465,000	)		(2,412,000	)

	Future Net Cash Flows			6,656,711			7,653,492
10% annual discount				(1,476,100	)		(1,479,544	)

		Standardized Measure	$	5,180,611		$	6,173,948

Changes in Standardized Measure

The following table sets forth the changes in standardized measure of discounted future net cash flows for the period from September 23, 2003 (inception) to December 31, 2003 and for the six months ended June 30, 2004:

	Six Months Ended June 30, 2004			For the Period From September 23, 2003 (Inception) to December 31, 2003
Standardized Measure, beginning	$	6,173,948		$	—
Net change in income taxes		737,006			(1,945,721	)
Oil and gas sales, net of costs		30,843			51,065
Purchase of minerals in place		—			8,068,605
Changes in prices and costs		82,230			—
Change in developments costs		(84,042	)		—
Accretion of discount		308,697			—
Revisions of estimates		(2,131,318	)		—
Other		64,246			—

Standardized Measure, ending	$	5,180,611		$	6,173,948

11. Subsequent Events

Subsequent to June 30, 2004, the Company received $475,000 under a short-term secured promissory note (the "Note") held by Laird Q. Cagan, the Company's Chairman and major stockholder, for the purpose of bridge financing part of the purchase price of the Tullos Urania Field. Under the terms of the Note, all net revenue derived from the Company's Tullos Urania Field, less operating expenses and development costs, must be applied toward repayment of the Note. The Note bears interest at 10% per annum, is secured by a pledge of all of the Company's assets and is due in full by February 10, 2005. Since the origination of the loan, the Company and Mr. Cagan agreed to amend the repayment terms of the loan by delaying the repayment until the earlier of (a) July 1, 2005, or (b) the date on which the cumulative gross equity funding after August 14, 2004 reaches $1 million. Also amended are the terms of the Note which delays the mandatory prepayment until all net revenue derived from the Company's Tullos Urania Field, less operating expenses and capital costs accruing after February 5, 2005 and 50% of the net proceeds of any related third party financings of any kind conducted by the Company after the date of this Note.

From July 1, 2004 through September 24, 2004, NGS raised gross proceeds from the sale of common stock in the amount of $544,734.

On September 2, 2004, NGS purchased its second property comprising a 100% working interest in approximately 81 producing oil wells, 8 salt water disposal wells and 54 shut-in wells located in La Salle and Winn Parishes, Louisiana. Fourteen of the shut-in wells will require a new lease prior to restoration of production. The purchase included leases covering 386.04 gross and net acres, and fee ownership of 2.33 acres around certain of the wells. NGS intends to initiate a program of restoring the shut-in wells to production, increasing overall production per well by addition of incremental water disposal capacity and utilizing gas production to replace purchased power for pumps. NGS will file at a later date a Form 8-K to further describe the purchased assets.

12. Income Taxes

The tax effect of significant temporary differences representing deferred tax assets and liabilities at December 31, 2003 and June 30, 2004 are as follows:

	June 30, 2004			December 31, 2003
Oil and gas properties	$	(69,389	)	$	(113,558	)
Net operating loss carryforwards		366,425			228,043
Valuation Allowance		(297,036	)		(114,485	)

Net deferred tax asset	$	—		$	—

The increase in the valuation allowance during fiscal 2003 and 2004 of $114,485 and $182,551; respectively, is the result of additional net tax losses incurred during the year.

As of June 30, 2004, the Company has net operating loss carryforwards of approximately $1,078,000 that will expire in 2023 and 2024. Future utilization of the net operating loss carryforwards and other tax attributes may be limited by changes in the ownership of the Company in May 2004 under section 382 of the Internal Revenue Code.

The following is a reconciliation of the Company's expected income tax expense (benefit) based on statutory rates to the actual expense (benefit):

	Six Months Ended June 30, 2004			For the Period From September 23, 2003 (Inception) to December 31, 2003
Income taxes (benefit) at US statutory rate	$	(349,412	)	$	(114,548	)
Non-deductible amortization and expenses		165,141			62
Deferred tax asset valuation allowance adjustment		182,551			114,485
Net operating losses		—			—

Other	$	1.720			1

	$	—		$	—

13. Liquidity

1.: Additional Sales of Common Stock: From June 30 through September 24, 2004 we received $544,734 of additional gross cash proceeds from the private sale of our common stock, before commissions. We plan to raise funds through additional sales of equity securities in private transactions. Because there can be no assurance that we will be able to do so, we are pursuing borrowing arrangements as discussed below.
2.: Borrowing: On August 11, 2004, we borrowed $475,000 under a short-term secured promissory note (the "Bridge") held by Laird Q. Cagan, the Company's Chairman and major stockholder, secured by a pledge of all of our assets. The loan was earmarked as partial bridge financing for our purchase of the Tullos Urania Field properties for $732,000 on September 3, 2004. The Bridge loan with Mr. Cagan has been amended to delay the repayment until the earlier of (a) July 1, 2005, or (b) the date on which the cumulative gross equity funding after August 14, 2004 reaches $1 million. Terms of the mandatory prepayment have also been amended as more fully described in the original documents filed or incorporated by reference herein. Mr. Cagan is a founding Managing Partner of Cagan McAfee Capital Partners, the financial advisor to the Company that is arranging private equity fundings. If additional funds

are not raised, we may not have sufficient funds to repay the Bridge loan or complete our capital expenditure program as currently contemplated.

3.: Increased Production: We continue to work on increasing cash flow from operations through our Delhi Field and additional acquisition candidates, thereby spreading our overhead, including significant expenses of being a public company, over a larger revenue base. On September 3, 2004, we closed the purchase of producing properties in the Tullos Urania Field, located close to our Delhi Field operations in Northern Louisiana. We believe that net cash flow from operations at our Tullos property currently exceeds $30,000 per month. We also believe that opportunities exist to increase Tullos production with relatively small amounts of additional capital expenditures.

We are pursuing additional acquisition candidates meeting our targeted requirements.

14. Leases

The Company is obligated for operating lease payments related to the Company's headquarters in Houston, Texas, and a gas processing plant servicing the Company's Delhi Field. Minimum lease payments are:

Fiscal 2005:	$	101,772
Fiscal 2006:		12,516

Total	$	114,288

Lease expense was $44,770 for the six months ended June 30, 2004 and $8,541 for the three months ended December 31, 2003.

15. Earnings Per Share

The following table sets forth the computation of basic and diluted earnings (loss) per share:

			Six Months Ended June 30, 2004			For the Period From September 23, 2003 (Inception) to December 31, 2003
Numerator:
	Net loss applicable to common stockholders		$	(1,027,682	)	$	(336,905	)
	Plus income impact of assumed conversions:
		Preferred stock dividends		N/A			N/A
		Interest on convertible subordinated notes		N/A			N/A

	Net loss applicable to common stockholders plus assumed Conversions			(1,027,682	)		(336,905	)
Denominator:
				22,057,614			20,091,720
Affect of potentially dilutive common shares:
	Warrants			N/A			N/A
	Employee and director stock options			N/A			N/A
	Convertible preferred stock			N/A			N/A
	Convertible subordinated notes			N/A			N/A
	Redeemable preferred stock			N/A			N/A

Denominator for dilutive earnings per share—weighted-average shares
	Outstanding and assumed conversions			22,057,614			20,091,720

Loss per common share:
	Basic and diluted		$	(0.05	)	$	(0.02	)

INDEPENDENT AUDITORS' REPORT

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders
Natural Gas Systems, Inc.
Houston, Texas

We have audited the accompanying consolidated balance sheets of Natural Gas Systems, Inc. as of June 30, 2004 and December 31, 2003 and the related consolidated statements of operations, stockholders' equity, and cash flows for the six months period ended June 30, 2004 and the period from September 23, 2003 (inception) to December 31, 2003. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes 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 consolidated financial statements referred to above present fairly, in all material respects, the financial position of Natural Gas Systems, Inc. and subsidiaries as of June 30, 2004 and December 31, 2003, and the results of their operations and their cash flows for each of the periods then ended, in conformity with accounting principles generally accepted in the United States of America.

HEIN & ASSOCIATES LLP

Houston, Texas
September 28, 2004

ITEM 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 8A. CONTROLS AND PROCEDURES

Our management evaluated, with the participation of our Chief Executive Officer and Chief Financial Officer, the effectiveness of our disclosure controls and procedures, as of the end of the period covered by this report. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company's disclosure controls and procedures are effective to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission's rules and forms.

There were no changes in our internal control over financial reporting that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 8B. OTHER INFORMATION

Subsequent Events

Subsequent to June 30, 2004, the Company and Laird Cagan, Chairman of the Company, agreed to amend the repayment terms of the outstanding bridge loan provided by Cagan to the Company in the amount of $475,000. Terms of the original loan and the amendment are discussed in Item 6, Management's Discussion and Analysis and are available herein or incorporated by reference in the exhibits hereto.

In September 2004, we placed on production two additional wells that were previously shut-in. The 184-2 well was recompleted into a stray gas sand and initially tested at a rate of 500 mcfd and 1120 psig flowing tubing pressure. Initial shut-in tubing pressure was 1350 psig with a perforated depth of 3,170-78'. The 210-2 well was placed back into production and initially made 5 BOPD while unloading wash water.

On September 2, 2004, we purchased our second property comprising a 100% working interest in approximately 81 producing oil wells, 8 salt water disposal wells and 54 shut-in wells located in La Salle and Winn Parishes, Louisiana. We purchased the property for $725,000, plus post closing adjustments, in cash. Fourteen of the shut-in wells will require a new lease prior to restoration of production. The production rate aggregates approximately 62 BOPD plus a small amount of associated gas that is not sold currently. The purchase included leases covering 386.04 gross and net acres, and fee ownership of 2.33 acres around certain of the wells. NGS intends to initiate a program of restoring the shut-in wells to production, increasing overall production per well by addition of incremental water disposal capacity and utilizing gas production to replace purchased power for pumps. We will file at a later date a Form 8-K to further describe the purchased assets including audited proved reserves and financial statements.

PART III.

ITEM 9. DIRECTORS AND EXECUTIVE OFFICERS